DELTA PETROLEUM CORP/CO - 10-K Annual Report

Check whether issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act) ¨ Yes No x

The aggregate market value as of September 7, 2004 of voting stock held by non-affiliates of the registrant was approximately $407,611,000.

As of September 10, 2004, 39,314,949 shares of registrant’s Common Stock $.01 par value were issued and outstanding.

Documents incorporated by reference: The information required by Part III of this Form 10-K is incorporated by reference to the Company’s Definitive Proxy Statement for the Company’s 2004 Annual Meeting of Shareholders.

The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation and its subsidiaries unless the context suggests otherwise.

CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the “safe harbor” protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. These statements may include projections and estimates concerning the timing and success of specific projects and our future (1) income, (2) oil and gas production, (3) oil and gas reserves and reserve replacement, (4) capital spending, and (5) other matters related to our business. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this report, the matters discussed in this report are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.

We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward-looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our shareholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere, and all of such forward-looking statements are qualified by this cautionary statement.

Delta Petroleum Corporation (“Delta,” “we” or “us”) is a Colorado corporation organized on December 21, 1984. We maintain our principal executive offices at 475 Seventeenth Street, Suite 1400, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on NASDAQ under the symbol DPTR.

We are primarily engaged in the acquisition, exploration, development and production of oil and gas properties. During fiscal 2004, we acquired a 50% interest in both a drilling and a trucking company, however these entities had limited activity. Our primary oil and gas areas of operations include the (1) Gulf Coast Region—South Texas and all Louisiana Basins, (2) Rocky Mountain Region - Denver Julesburg, Wind River, Williston and Piceance Basins, and (3) Offshore California near Santa Barbara.

The following table presents information regarding our primary oil and gas areas of operations as of June 30, 2004:

We intend to develop our primary areas of operations. For fiscal 2005, we have established an exploration and development capital budget of approximately $80 million.

We have oil and gas leases with governmental entities and other third parties who enter into oil and gas leases or assignments with us in the regular course of our business. We have no material patents, licenses, franchises or concessions that we consider significant to our oil and gas operations. The nature of our business is such that it is not seasonal, we do not engage in any research and development activities and we do not maintain or require a substantial amount of products, customer orders or inventory. Our oil and gas operations are not subject to renegotiations of profits or termination of contracts at the election of the federal government. We operate the majority of our properties and control the costs incurred. We have never been a party to any bankruptcy, receivership, reorganization or similar proceeding.

On June 29, 2004, we acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc. (“Alpine”) for a total purchase price of $120.6 million, net of $1.9 million downward purchase price adjustment. Alpine was a privately held exploration and production company, active primarily in Southeast Texas and Louisiana.

Subsequent to year-end on August 19, 2004, we completed the sale of our interests in five fields in Louisiana and South Texas previously acquired in the Alpine Acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $19.3 million. We paid $8.8 million toward our credit facility relating to the sale of these properties. No gain or loss was recorded on this transaction.

On September 19, 2003, we completed an acquisition of certain producing and drilling prospects in Colorado (the “South Tongue Prospect”) and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”). On the date of acquisition, we estimated proved reserves to be approximately 4.7 Bcfe and we also acquired 100,000 acres of prospect leases in the South Tongue Prospect in Washington County, Colorado and 20,000 acres of prospect leases in Wyoming for total consideration of $13.1 million net of normal closing adjustments. Subsequent to September 19, 2003, we increased our South Tongue acreage position to approximately 260,000 acres.

On April 22, 2004, we amended our agreement with Davis to, among other things, add certain oil and gas leases located in Colorado known as the “North Tongue Prospect,” decrease the amount of Davis’ reversionary working interest after payout in the properties acquired under the initial agreement from 50% to 42.5%, change the definition of payout, change certain drilling obligations and modify our obligation to issue additional shares of stock to Davis upon the designation of Bonus Prospects. The initial consideration required to be paid to Davis upon execution of the Amended Agreement was 1,525,000 shares of our common stock, valued at $17.3 million. The entire amount was allocated to unproved undeveloped properties.

On June 20, 2003, we acquired producing oil and gas interests and related undeveloped acreage in Kansas from JAED Production Company (“JAED”). On the date of acquisition, we estimated proved reserves to be approximately 9.9 Bcfe for total consideration of $8.7 million net of normal closing adjustments.

On May 31, 2002, we acquired all of the domestic oil and gas properties of Castle Exploration Company (“Castle”). The properties acquired from Castle consisted of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. On the date of acquisition, we estimated proved reserves to be approximately 62 Bcfe, of which 32 Bcfe was considered to be proved developed producing reserves for total consideration of $40.8 million net of $5.8 million in closing adjustments.

On February 19, 2002, we completed the acquisition of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. We issued 1,377,240 shares of our restricted common stock for 100% of the shares of Piper. The 1,377,240 shares of restricted common stock were valued at approximately $5.2 million based on the five-day average market closing price of Delta’s common stock surrounding the announcement of the merger.

We have an authorized capital of 3,000,000 shares of $.10 par value preferred stock, of which no shares were issued, and 300,000,000 shares of $.01 par value common stock, of which 38,447,369 shares were issued and outstanding as of June 30, 2004. We have outstanding warrants and options to non-employees to purchase 57,500 shares of common stock at prices ranging from $3.25 per share to $5.00 per share at June 30, 2004. Additionally, as of June 30, 2004 we had outstanding options which were granted to our officers, employees and directors under our incentive plans, to purchase up to 4,700,772 shares of common stock at prices ranging from $0.05 to $13.43 per share.

On June 29, 2004, we increased our credit facility to $100 million with a current borrowing base of $70 million with Bank of Oklahoma, N.A., US Bank National Association and Hibernia National Bank (the “Banks”). The proceeds from the increase in our credit facility were used for the Alpine acquisition.

At June 30, 2004, we owned 4,277,977 shares of common stock of Amber Resources Company (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company (registered under the Securities Exchange Act of 1934) which owns non-operated working interests in undeveloped leases offshore California, near Santa Barbara. On July 1, 2001, we purchased all the producing properties of Amber for $107,000. The purchase price was based on an evaluation performed by an unrelated engineering firm. The effects of this transaction are eliminated in the consolidated financial statements. We entered into an agreement with Amber effective October 1, 1998 which provides, in part, for the sharing of the management between the two companies and allocation of expenses related thereto.

During the year ended June 30, 2004, we were engaged in only one industry, namely the acquisition, exploration, development, and production of oil and gas properties and related business activities. Our oil and gas operations have been comprised primarily of production of oil and gas, drilling exploratory and development wells and related operations and acquiring and selling oil and gas properties. Directly or through wholly-owned subsidiaries and through Amber, we currently own producing and non-producing oil and gas interests, undeveloped leasehold interests and related assets in fifteen (15) states, interests in a producing Federal unit offshore California and undeveloped offshore Federal leases near Santa Barbara, California. We intend to continue our emphasis on the drilling of exploratory and development wells primarily in Alabama, Colorado, Louisiana, New Mexico, Texas, Wyoming, and offshore California.

We intend to drill on some of our leases (presently owned or subsequently acquired); we may farm out or sell all or part of some of the leases to others; and/or we may participate in joint venture arrangements to develop certain other leases. Such transactions may be structured in a number of different manners that are in use in the oil and gas industry. Each such transaction is likely to be individually negotiated and no standard terms may be predicted.

During fiscal 2004 we also acquired a fifty percent interest in a small drilling company and a fifty percent interest in a small trucking company. Although we did not engage in any material drilling operations during fiscal 2004, our ownership interest in the drilling company will allow us to have priority access to at least two large drilling rigs. The initial purpose of our investment in the trucking company is to allow these drilling rigs to be moved to new drilling locations as necessary.

The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and gas are refineries and transmission companies which have facilities near our producing properties.

Oil and natural gas produced from our wells are normally sold to various purchasers as discussed below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil, which fee is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas.

We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and the development and production of, natural gas and crude oil. Competition is particularly intense with respect to the acquisition of desirable undeveloped gas and oil leases. The principal competitive factors in the acquisition of undeveloped gas and oil leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have financial resources, staffs and facilities substantially greater than ours. In addition, the producing, processing and marketing of natural gas and crude oil are affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. See “Risk Factors.”

The principal raw materials and resources necessary for the exploration and development of natural gas and crude oil and leasehold prospects under which gas and oil reserves may be discovered, drilling rigs and related equipment to drill for and produce such reserves and knowledgeable personnel to conduct all phases of gas and oil operations. Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, we recently acquired a fifty percent interest in a small drilling company and a fifty percent interest in a small trucking company. We believe that our ownership interest in the drilling company will provide us with at least two large drilling rigs. The initial purpose of our investment in the trucking company is to allow these drilling rigs to be moved to new drilling locations as necessary. We are also attempting to establish arrangements with others to assure adequate availability of certain other necessary drilling equipment and supplies on satisfactory terms, but there can be no assurance that we will be able to do so. Accordingly, there can be no assurance that we will not experience shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to meet our drilling commitments.

During our fiscal year ended June 30, 2004, we sold a significant portion of our oil and gas production to the following companies: Seminole, Texla, Gulfmark, and Plains Marketing. We do not depend upon one or a few major customers for the sale of oil and gas as of the date of this report. The loss of any one or several customers would not have a material adverse effect on our business.

Our business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry.

The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.

Together with other companies in the industries in which we operate, our operations are subject to numerous federal, state, and local environmental laws and regulations concerning our oil and gas operations, products and other activities. In particular, these laws and regulations require the acquisition of permits, restrict the type, quantities, and concentration of various substances that can be released into the environment, limit or prohibit activities on certain lands lying within wilderness, wetlands and other protected areas, regulate the generation, handling, storage, transportation, disposal and treatment of waste materials and impose criminal or civil liabilities for pollution resulting from oil, natural gas and petrochemical operations.

Governmental approvals and permits are currently, and may in the future be, required in connection with our operations. The duration and success of obtaining such approvals are contingent upon a significant number of variables, many of which are not within our control. To the extent such approvals are required and not obtained, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or operation of facilities.

Environmental laws and regulations are expected to have an increasing impact on our operations, although it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. Some risk of environmental costs and liabilities is inherent in our operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. However, we do not currently expect any material adverse effect upon our results of operations or financial position as a result of compliance with such laws and regulations.

Although future environmental obligations are not expected to have a material adverse effect on our results of operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs.

We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some of these properties have been operated by third parties over whom we had no control. The U.S. Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liabilities on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum related products.

In addition, although RCRA currently classifies certain exploration and production wastes as “non-hazardous,” such wastes could be reclassified as hazardous wastes, thereby making such wastes subject to more stringent handling and disposal requirements. If such a change in legislation were to be enacted, it could have a significant impact on our operating costs, as well as the gas and oil industry in general.

Under the Federal Oil Pollution Act of 1990, as amended (“OPA”), (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located and (iii) owners and operators of tank vessels (“Responsible Parties”) are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into the navigable waters of the United States. These damages include, for example, natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350 million in the case of onshore facilities, $75 million plus removal costs in the case of offshore facilities, and in the case of tank vessels, an amount based on gross tonnage of the vessel. However, these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances.

In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150 million. Tank vessels must provide such evidence in an amount based on the gross tonnage of the vessel. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties.

Under our various agreements, we have primary liability for oil spills that occur on properties for which we act as operator. With respect to properties for which we do not act as operator, we are generally liable for oil spills as a non-operating working interest owner. We do not act as operator for any of our offshore California properties. The operators of our offshore California properties are primarily liable for oil spills and are required by the Minerals Management Service of the United States Department of the Interior (“MMS”) to carry certain types of insurance and to post bonds in that regard. In addition, we also carry insurance as a non-operator in the amount of $5 million onshore and $10 million offshore. There is no assurance that our insurance coverage is adequate to protect us.

Offshore oil and gas operations in U.S. waters are subject to regulations of the United States Department of the Interior which currently impose strict liability upon the lessee under a Federal lease for the cost of clean-up of pollution resulting from the lessee’s operations, and such lessee could be subject to possible liability for pollution damages. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under Federal leases to suspend or cease operations in the affected areas.

Because we are engaged in acquiring, operating, exploring for and developing natural resources, we are subject to various state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, however, these laws do not materially hinder nor adversely affect our business. Capital expenditures relating to environmental control facilities have not been material to our operation since our inception. In addition, we do not anticipate that such expenditures will be material during the fiscal year ending June 30, 2005.

We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties, pro rata to our working interest. As of January 1, 2003 we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations”. SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. We recorded an asset retirement obligation of approximately $2.6 million at June 30, 2004. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates, and changes to environmental laws and regulations. Estimated asset retirement obligations are added to net unamortized historical oil and gas property costs for purposes of computing depreciation, depletion and amortization expense charges.

We have approximately 50 full time employees. Additionally, certain operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required.

Owners of common stock are subject to a variety of risks, including, without limitation, the following:

1. We may issue shares of preferred stock with greater rights than our common stock.

Although we have no current plans, arrangements, understandings or agreements to issue any preferred stock, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our shareholders. Any preferred stock that is issued may rank ahead of our common stock, in terms of dividends, liquidation rights and voting rights.

To the extent options to purchase common stock under our employee and director stock option plans are exercised, holders of our common stock will incur dilution. Further, if we sell additional equity or convertible debt securities, such sales could result in increased dilution to our shareholders.

3. Our management controls a significant percentage of our outstanding common stock and their interests may conflict with those of our shareholders.

As of June 30, 2004, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 29% of our outstanding common stock. In addition, one of our affiliates, Castle Energy Corporation, has agreed to vote in favor of all of management’s nominees for director and in favor of other matters recommended by our Board of Directors at annual shareholder meetings. This concentration of voting control gives our directors and executive officers and their respective affiliates substantial influence over any matters that require a shareholder vote, including, without limitation, the election of directors, even if their interests may conflict with those of other shareholders. It could also have the effect of delaying or preventing a change in control of or otherwise discouraging a potential acquirer from attempting to obtain control of us. This could have a material adverse effect on the market price of our common stock or prevent our shareholders from realizing a premium over the then prevailing market prices for their shares of common stock.

4. Sales of substantial amounts of our common stock may adversely affect our stock price and make future offerings to raise capital difficult.

Sales of a large number of shares of our common stock in the market or the perception that sales may occur could adversely affect the trading price of our common stock. As of June 30, 2004, 38,447,369 shares of our common stock were outstanding, almost all of which currently are freely tradable, subject to certain volume limitations and other requirements applicable to affiliates. We recently issued 6,000,000 restricted shares to investors in a private placement of our shares and issued an additional 2,525,000 restricted shares to Edward Mike Davis and entities controlled by him. We have registered all 2,525,000 shares for resale. As of June 30, 2004, options to purchase up to a total of approximately 4,758,272 shares of our common stock were outstanding.

We may issue additional restricted securities or register additional shares of common stock under the Securities Act in the future for our use in connection with future acquisitions. Pursuant to Securities Act Rule 145, the volume limitations and certain other requirements of Rule 144 would apply to resales of these shares by affiliates of the businesses that we acquire for a period of one year from the date of their acquisition, but otherwise these shares would be freely tradable by persons not affiliated with us unless we contractually restrict their resale.

The availability for sale, or sale, of the shares of common stock eligible for future sale could adversely affect the market price of our common stock.

5. Provisions in some of our employment agreements with key employees could delay or prevent a change in control of our Company, even if that change would be beneficial to our shareholders.

Certain provisions in employment agreements with certain of our key employees provide that in the event of a change of control of our Company we will immediately cause all of such employees’ then outstanding unexercised options to be exercised by us on behalf of such employees and that we will pay all related federal, state and local taxes applicable to such exercise. Such provisions could delay, discourage, prevent or render more difficult an attempt to obtain control of our Company, whether through a tender offer, business combination, proxy contest or otherwise. These employment agreements terminate November 1, 2004.

We do not expect to pay any dividends, in cash or otherwise, with respect to our common stock in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreement relating to our $100 million credit facility with the Bank of Oklahoma, U.S. Bank and Hibernia Bank prohibits us from paying any dividends until the loan is retired.

As an equity interest, the common stock will not be secured by any of our assets. Therefore, in the event we are liquidated, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the common stock.

Holders of our common stock are not entitled to accumulate their votes for the election of directors or otherwise. Accordingly, the holders of more than 50% of our outstanding common stock will be able to elect all of our directors. As of June 30, 2004, our directors and executive officers and their respective affiliates collectively and beneficially owned approximately 29% of our outstanding common stock.

9. Our Articles of Incorporation have provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment.

Certain provisions of our Articles of Incorporation and the provisions of the Colorado Business Corporation Act may discourage persons from considering unsolicited tender offers or other unilateral takeover proposals. Such persons might choose to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions could have the effect of preventing shareholders from realizing a premium on their investment.

Our Articles of Incorporation authorize our Board of Directors to issue preferred stock without shareholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the Board may determine. Additional provisions include restrictions on business combinations and the availability of authorized but unissued common stock. These provisions may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to shareholders for their common stock.

1. We have substantial debt obligations, and shortages of funding could hurt our future operations.

As the result of debt obligations that we have incurred in connection with purchases of oil and gas properties, we are at times obligated to make substantial monthly payments to our lenders on loans that encumber our oil and gas properties and our production revenue. As of June 30, 2004, we owed Bank of Oklahoma, U.S. Bank and Hibernia Bank, collectively, $69.4 million, which was all that we were permitted to borrow under our existing credit facility. In the event that oil and gas prices and/or production rates drop to a level such that we are unable to pay the minimum principal and interest payments that are required by our debt agreements, we would be in default under our credit facility. In addition, our level of oil and gas activities, including exploration and development of existing properties, and additional property acquisitions, will be significantly dependent on our ability to successfully complete funding transactions.

Our credit facility with Bank of Oklahoma, U.S. Bank and Hibernia Bank allows us to borrow, repay and re-borrow amounts, up to a maximum amount of $100 million. In order to obtain this facility, we granted a first and prior lien to the lending banks on most of our oil and gas properties, certain related equipment, oil and gas inventory, and certain bank accounts and proceeds. Under the terms of our credit agreement, the oil and gas properties mortgaged must represent not less than 80% of the engineered value of our oil and gas properties as determined by the Bank of Oklahoma using its own pricing parameters.

Our borrowing base, which determines the amounts that we are allowed to borrow or have outstanding under our credit facility, was $69.4 million as of June 30, 2004. Subsequent determinations of our borrowing base will be made by the lending banks at least semi-annually on October 1 and April 1 of each year or as unscheduled redeterminations. In connection with each determination of our borrowing base, the banks will also redetermine the amount of our monthly commitment reduction. We do not currently have any monthly commitment reduction obligation as a result of our most recent redetermination, and we will not have any monthly commitment reduction obligation until it is redetermined by our banks. Our borrowing base and the revolving commitment of the banks to lend money under the credit agreement must be reduced as of the first day of each month by an amount determined by the banks under our credit agreement. The amount of the borrowing base must also be reduced from time to time by the amount of any prepayment that results from our sale of oil and gas properties. If, as a result of any such monthly commitment reduction or reduction in the amount of our borrowing base, the total amount of our outstanding debt were to exceed the amount of the revolving commitment then in effect, then, within 30 days after we are notified by the Bank of Oklahoma, we would be required to make a mandatory prepayment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base. If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit agreement.

For so long as the revolving commitment is in existence or any amount is owed under any of the loan documents, we will also be required to comply with loan covenants that will limit our flexibility in conducting our business and which could cause us significant problems in the event of a downturn in the oil and gas market. If an event of default occurs and continues after the expiration of any cure period that is provided for in our credit agreement, the entire principal amount due under the loan documents, all accrued interest and any other liabilities that we might have to the lending banks under the loan documents will all become immediately due and payable, all without notice of default of any kind. The foregoing information is provided to alert readers that there is risk associated with our existing debt obligations. It is not intended to provide a summary of the terms of our agreements with our lenders.

3. The substantial cost to develop certain of our offshore California properties could result in a reduction of our interest in these properties or cause us to incur penalties.

Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 75%, are attributable to our interests in four of our five federal units (plus one additional lease) located offshore of California near Santa Barbara. These properties have a cost basis of $10.8 million. The cost to develop these properties will be very substantial. The cost to develop all of these offshore California properties in which we own an interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be in excess of $3 billion. Our share of such costs, based on our current ownership interest, is estimated to be over $200 million. Operating expenses for the same properties over the same period of time, including platform operating costs, well maintenance and repair costs, oil, gas and water treating costs, lifting costs and pipeline transportation costs, are estimated to be approximately $3.5 billion, with our share, based on our current ownership interest, estimated to be approximately $300 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. If we are unable to fund our share of these costs or otherwise cover them through farmouts or other arrangements, then we could either forfeit our interest in certain wells or properties or suffer other penalties in the form of delayed or reduced revenues under our various unit operating agreements. The estimates discussed above may differ significantly from actual results.

4. If we fail to drill in accordance with the terms of our existing agreements, we could lose some of our properties in Washington County, Colorado.

We have entered into agreements, which require us to fulfill certain drilling obligations. In particular, we have entered into an agreement with Edward Mike Davis and entities controlled by him (“Davis”) which requires us to drill wells on not less than ten prospects during every twelve month period in our area of mutual interest in Washington County, Colorado, and as to each successful prospect well, to continuously drill additional wells to fully develop each prospect as a result of such drilling with the goal of establishing ten-acre spacing for each such oil discovery. Our agreement with Davis provides that if at any time we fail, but for reasons of acts of God or lack of availability of a drilling rig, to honor the drilling program, we are to reassign to Davis all lease acreage in our area of mutual interest not held by production, but we are to have no other liability to Davis or any other party for our failure to drill. We have agreed to drill all wells to the base of the J-Sand Formation or the top of the Skull Creek Formation. Our past J-Sand results have initially caused us to believe that the eastern half of our acreage position in our area of mutual interest will be productive in the shallow Niobrara formation, but may not be productive in the deeper J-Sand. Although we currently intend to continue to drill to the J-Sand in that area because in many locations the formation may be economically viable and continued drilling to that depth will provide us with additional information which may prove to be beneficial to us in the future, if we ultimately determine that it is not worthwhile to drill to the depth of the J-Sand or otherwise fail to drill to that depth in accordance with the terms of our agreement, we may be required to assign acreage to Davis. Davis has notified us that he does not believe that we are fulfilling all of our obligations under this and other agreements with him, but he has not declared us to be in default. We intend to fully comply with all of our obligations under these agreements.

5. There is currently a shortage of available drilling rigs and equipment which could cause us to experience higher costs and delays that could adversely affect our operations.

Although equipment and supplies used in our business are usually available from multiple sources, there is currently a general shortage of drilling equipment and supplies. We believe that these shortages are likely to intensify. The costs and delivery times of equipment and supplies are substantially greater now than in prior periods and are currently escalating. In partial response to this trend, we recently acquired a fifty percent interest in a small drilling company and a fifty percent interest in a small trucking company that are both currently managed by Edward Mike Davis. Although Mr. Davis and his affiliated entities are not currently deemed to be affiliates of Delta, we have recently acquired several properties from Mr. Davis and entities that are controlled by him. We also currently have areas of mutual interest and joint ventures with Mr. Davis and his related entities, and we have substantial drilling commitments that are related to those ventures. We believe that our ownership interest in the drilling company will allow us to have priority access to at least two large drilling rigs. The initial purpose of our investment in the trucking company is to allow these drilling rigs to be moved to new drilling locations as necessary. We are also attempting to establish arrangements with others to assure adequate availability of certain other necessary drilling equipment and supplies on satisfactory terms, but there can be no assurance that we will be able to do so. Accordingly, there can be no assurance that we will not experience shortages of, or material price increases in, drilling equipment and supplies, including drill pipe, in the future. Any such shortages could delay and adversely affect our ability to meet our drilling commitments.

We do not have any long-term supply or similar agreements with governments or other authorities for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing wellhead market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable.

Since all of our resources are devoted to one industry, owners of our common stock are risking essentially their entire investment in a company that is focused only on oil and gas activities.

We currently have only four employees that serve in management roles, and the loss of any one of them could severely harm our business. In particular, Roger A. Parker and John R. Wallace are responsible for the operation of our oil and gas business, Aleron H. Larson, Jr. is responsible for other business and corporate matters, and Kevin K. Nanke is our chief financial officer. We do not have key man insurance on the lives of any of these individuals.

1. Oil and natural gas prices are volatile and a decrease could adversely affect our revenues, cash flows and profitability.

Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Sustained declines in oil and gas prices may adversely affect our financial condition, liquidity and results of operations. Factors that can cause market prices of oil and natural gas to fluctuate include: relatively minor changes in the supply of and demand for oil and natural gas; market uncertainty; the level of consumer product demands; weather conditions; U.S. and foreign governmental regulations; the price and availability of alternative fuels; political and economic conditions in oil producing countries, particularly those in the Middle East; the foreign supply of oil and natural gas; the price of oil and gas imports; and overall U.S. and foreign economic conditions.

We are not able to predict future natural gas or oil prices. At various times, excess domestic and imported supplies have depressed oil and gas prices. Lower prices may reduce the amount of oil and natural gas that we can produce economically and may also require us to write down the carrying value of our oil and gas properties. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts.

In an attempt to reduce price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. Such transactions may not reduce the risk or minimize the effect of any decline in natural gas or oil prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.

2. If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we may be required to take write downs.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. A write down could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results.

We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we must write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are developmental in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded book values associated with our oil and gas properties.

3. The marketability of our production depends mostly upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities.

The marketability of our production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. United States federal, state and foreign regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

Our revenues are derived principally from uncollateralized sales to customers in the oil and gas industry. The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. We generally do not attempt to obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict, however, what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.

5. We may not be able to obtain adequate financing to execute our operating strategy.

We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, the use of bank credit facilities and the issuance of equity securities. Without adequate financing, we may not be able to successfully execute our operating strategy, particularly with respect to our offshore California properties. We continue to examine the following alternative sources of capital:

The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices and our market value and operating performance. We may be unable to execute our operating strategy if we cannot obtain adequate capital.

We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. Our exploration and development capital budget ranges from $60 to $80 million for fiscal 2005. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures. After utilizing our available sources of financing, we may be forced to raise additional equity or debt proceeds to fund such expenditures. Additional equity or debt financing or cash flow provided by operations may not be available to meet our capital expenditures requirements.

Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves and developing existing proved reserves, which we may not be successful in doing.

The successful acquisition of producing properties requires an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, the review will not permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not be able to acquire properties at acceptable prices because the competition for producing oil and gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us.

8. The exploration, development and operation of oil and gas properties involve substantial risks that may result in a total loss of investment.

The business of exploring for and, to a lesser extent, developing and operating oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Currently, 42% of our proved reserves are undeveloped and have a book value of $86.7 million. The cost to develop these reserves is estimated to be approximately $67 million. In addition, we have $49 million of capitalized costs on properties with no proved reserves. We may drill wells that are unproductive or, although productive, do not produce oil and/or gas in economic quantities. Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, a successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market-related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the availability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic in the event water or other deleterious substances are encountered which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.

9. You should not place undue reliance on reserve information because it is only an estimate.

Certain of our Exchange Act reports filed with the Commission contain estimates of oil and gas reserves, and the future net cash flows attributable to those reserves, prepared by Ralph E. Davis Associates, Inc. and Mannon & Associates (together, the “Engineers”), our independent petroleum and geological engineers. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the Engineers’ control. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of oil and gas reserves, or of cash flows attributable to such reserves, is a function of the available data, assumptions regarding future oil and gas prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and oil and gas prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our Exchange Act reports filed with the Commission, certain of which are incorporated by reference into this report. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in certain of the Exchange Act reports were prepared by the Engineers in accordance with the rules of the Commission, and are not intended to represent the fair market value of such reserves.

10. Our operations are subject to numerous risks of oil and gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be found. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services.

New wells that we drill may not be productive and we may not recover all or any portion of our investment. The cost of drilling and completing wells is often uncertain. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs to recoup drilling costs.

The exploration, development and operation of oil and gas properties also involve a variety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards, including oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. If any of these industry-operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations.

We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to those attacks may make some types of insurance more difficult to obtain. We may be unable to secure the level and types of insurance we would otherwise have secured prior to the terrorist attacks. We may not be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could materially and adversely affect our financial condition and operations.

12. Terrorist attacks aimed at our facilities could adversely affect our business.

The United States has been the target of terrorist attacks of unprecedented scale. The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse effect on our business.

13. We may suffer losses or incur liability for events that we or the operator of a property has chosen not to obtain insurance.

Our operations are subject to hazards and risks inherent in producing and transporting oil and natural gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and others. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, we believe any operators of properties in which we have or may acquire an interest will maintain similar insurance coverage. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operation.

In order to manage our exposure to price risks in the marketing of oil and gas, we periodically enter into oil and gas price hedging arrangements, such as commodity swap agreements, forward sale contracts, commodity futures, options and similar agreements, with respect to a portion of our expected production. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

15. We may incur substantial costs to comply with the various U.S. federal, state and local environmental laws and regulations that affect our oil and gas operations.

Our oil and gas operations are subject to stringent U.S. federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the incurrence of investigatory or remedial obligations, or the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Over the years, we have owned or leased numerous properties for oil and gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of previously released materials or property contamination at such locations regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

We own a fifty percent interest in a drilling business. Our operations through that entity will subject us to many additional hazards that are inherent to the drilling business, including, for example, blowouts, cratering, fires, explosions, loss of well control, loss of hole, damaged or lost drill strings and damage or loss from inclement weather. Although we believe that our drilling business is adequately insured for public liability and property damage to others and injury or death to persons in accordance with industry standards with respect to its operations, no assurance can be given that such insurance will be sufficient to protect it against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. No assurance can be given that our drilling business will be able to maintain adequate insurance in the future at rates it considers reasonable or that any particular types of coverage will be available. The occurrence of events, including any of the above-mentioned risks and hazards, that are not fully insured could subject our drilling business to significant liability. It is also possible that we might sustain significant losses through the operation of the drilling business even if none of such events occurs.

The following discussion describes our primary oil and gas areas. We believe these areas will have a significant contribution to our daily production and future reserve growth.

The Gulf Coast Region comprises approximately 55.8% of our estimated proved reserves at June 30, 2004. We did not drill and complete a significant number of wells in this region because a majority of the drilling prospect inventory was acquired through the Alpine Resources acquisition, which did not close until June 29, 2004.

In South Texas, our primary activities will be an extensive drilling program to continue the development of two large value fields (Newton Field in Newton County and South Angleton Field in Brazoria County), which were previously owned by Alpine Resources. We will also have additional development in other areas of South Texas which includes activity on properties we own in Polk County, Liberty County, Arkansas County and McMullen County. Working interest ownership is between 50% and 100% and operated by us.

In Louisiana, we plan additional development on properties in Point Coupee and Iberville Parishes. The majority of these properties are operated and owned 100% by us.

The Denver Julesburg and Piceance Basins of Colorado and the Wind River Basin of Wyoming account for a major portion our current and projected exploration and development activities. Approximately 7.3% of our estimated proved reserves are located in these areas at June 30, 2004. We own and operate interests in 40 producing wells in these basins and the net daily production was approximately 6,000 Mcfge (thousand cubic feet of gas equivalent) as of June 30, 2004. We have approximately 280,000 net acres of developed and undeveloped acres in these basins.

In the Denver Julesburg Basin, we have already identified 135 locations to be drilled and we are also continuing our 3D seismic program, with the intent of collecting seismic on all 260,000 acres we own. Due to a high degree of success in predicting wells resulting from 3D seismic surveys, we plan to concentrate a majority of our 2005 capital expense drilling in this area. We own 100% of the working interest in our acreage in the Denver Julesburg Basin.

The Piceance Basin was not a focal point of development in 2004, but should see extensive drilling in 2005 as a result of increased well productivity, lower completion costs and higher natural gas prices. We own and operate a majority of our interests in the Piceance Basin. Our total acreage position is approximately 10,600 net acres that may ultimately allow for the drilling of up to 700 wells.

In the Wind River Basin, we drilled 18 wells and as of June 30, 2004 nine have been completed and the other nine are in various stages of being completed. The majority of the drilling was in the Fuller Reservoir Field. The Fuller Reservoir Field will be a focus of development in 2005. We operate the wells and own a significant portion of the working interest (75% on average). In addition, we will begin drilling activity on our Howard Ranch properties.

We have ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $10.8 million and $10.2 million at June 30, 2004 and 2003, respectively. These non-operated property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of our investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.

Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, we believe the fair values of our property interests are in excess of their carrying values at June 30, 2004 and that no impairment in the carrying values has occurred. Pursuant to a ruling in California v. Norton, later affirmed by the 9th Circuit Court of Appeals, the U.S. Government is required to make a consistency determination relating to the 1999 lease suspension requests under a 1990 amendment to the Coastal Zone Management Act. In the event that there is some future adverse ruling under the Coastal Zone Management Act that we decide not to appeal or that we appeal without success, it is likely that some or all of our interests in these leases would become impaired and written off at that time. It is also possible that other events could occur during the Coastal Zone Management Act review or appellate process that would cause our interests in the leases to become impaired, and we will continuously evaluate those factors as they occur. On January 9, 2002, Delta and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of the Company’s Offshore California properties. See “Legal Proceedings.”

We own an 11.11% interest in the east half of OCS Block 451 and a 100% interest in OCS Blocks 452 and 453, which leases comprise the undeveloped Rocky Point Unit. On November 2, 2000 we entered into an agreement with all of the interest owners of the Point Arguello unit for the development of Rocky Point and agreed, among other things, that Arguello, Inc. would become the operator of Rocky Point. Six test wells have been drilled on these leases from mobile drilling units. Five were successful and one was a dry hole. OCS-P 0451 #1, drilled in 1982, was the discovery well for the Rocky Point Field. Five delineation wells were drilled on the Unit between 1982 and 1984. Rates up to 1,500 Bbls of oil per day were tested from the Monterey formation. Rates up to 3,500 Bbls of oil per day were tested from the lower Sisquoc formation which overlies the Monterey. Oil gravities at Rocky Point range from 24 degrees to 31 degrees API.

Development of the Rocky Point Unit will be accomplished through extended-reach drilling from the platforms located within the adjacent Point Arguello Unit (see below). In 1987 an extended-reach well was successfully drilled to the southwestern edge of the Rocky Point field from Platform Hermosa located in the Point Arguello Unit. Since that time the technology of extended-reach drilling has dramatically advanced. The entire Rocky Point field is now within drilling distance from the Point Arguello Unit platforms.

We are currently drilling our first development well on the Rocky Point Unit. The well is being drilled to a total measured depth of 18,000 feet and we should have results sometime in September. By virtue of various agreements between owners of the Point Arguello Unit platforms and the Rocky Point Unit leasehold, Delta will have approximately a 6.25% working interest in the development of the east half of OCS Block 451.

Point Arguello Unit. Whiting Petroleum Corporation holds, as our nominee, the equivalent of a 6.07% working interest in form of a financial arrangement termed a “net operating interest” in the Point Arguello Unit and related facilities. In layman’s terms, the term “net operating interest” is defined in our agreement with Whiting as being the positive or negative cash flow resulting to the interest from a seven step calculation which in summary subtracts royalties, operating expenses, severance taxes, production taxes and ad valorem taxes, capital expenditures, unit fees and certain other expenses from the oil and gas sales and certain other revenues that are attributable to the interest. Within this unit are three producing platforms (Hidalgo, Harvest and Hermosa) which are operated by Arguello, Inc., a subsidiary of Plains Resources Corporation. In an agreement between Whiting and us (see Form 8-K dated June 9, 1999), Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities.

Our offices are located at 475 Seventeenth Street, Suite 1400, Denver, Colorado 80202. We lease approximately 19,000 square feet of office space for approximately $25,000 per month and the lease will expire in September, 2008.

During the years ended June 30, 2004, 2003 and 2002 we have not had, nor do we now have, any long-term supply or similar agreements with governments or authorities under which we acted as producer.

We acquired many of our offshore properties (including our interest in Amber) in a series of transactions from 1992 to the present. These properties are carried at our cost basis, $10.8 million, and have been subject to an impairment review on an annual basis.

These properties will be expensive to develop and produce and have been subject to significant regulatory restrictions and delays. Substantial quantities of hydrocarbons are believed to exist based on estimates reported to us by the operator of the properties and the U.S. government’s Mineral Management Services. The classification of these properties depends on many assumptions relating to commodity prices, development costs and timetables. We annually consider impairment of properties assuming that properties will be developed. Based on the range of possible development and production scenarios using current prices and costs, we have concluded that the cost bases of our offshore properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investment in such properties.

Unproved onshore properties are carried at our cost basis, $38.9 million, and have been subject to an impairment review on an annual basis. There are no proven reserves associated with these properties. Based on our continued interest in these properties and the possibility for future development, we have concluded that the cost basis of these other undeveloped properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investments in such properties.

We annually compare our historical cost basis of each proved developed and undeveloped oil and gas property to its expected future undiscounted cash flow from each property (on a field by field basis). Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the property, no impairment is recognized. If the carrying value of the property exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset.

We had an impairment provision attributed to producing properties during the year ended June 30, 2002 of $878,000 and none during the years ended June 30, 2004 and 2003.

Any impairment provisions recognized for developed and undeveloped properties are permanent and may not be restored in the future periods.

The following table sets forth certain information regarding our volumes of production sold and average prices received associated with our production and sales of natural gas and crude oil for each of the years ended June 30, 2004, 2003 and 2002.

The table below shows, as of June 30, 2004, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and by Amber. Productive wells are producing wells capable of production, including shut-in wells. Developed acreage consists of acres spaced or assignable to productive wells.

During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells:

The following represents our planned exploration and development activities for fiscal 2005.

On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. Our claim for lease bonuses and rentals paid by us and our predecessors is in excess of $152 million. In addition, our claim for exploration costs and related expenses will also be substantial. In the event, however, that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties.

The Federal Government has not yet filed an answer in this proceeding pending its motion to dismiss the lawsuit, and the plaintiffs have filed a motion for summary judgment as to certain liability aspects related to their claims. Neither motion has yet been heard by the court.

No matter was submitted to a vote of security holders during the fourth quarter of our fiscal year.

The following information with respect to Executive Officers and Directors is furnished pursuant to Item 401(a) of Regulation S-K.

The following is biographical information as to the business experience of each of our current officers and directors.

Roger A. Parker has operated as an independent in the oil and gas industry individually and through public and private ventures since 1982. He was at various times, from 1982 to 1989, a Director, Executive Vice President, President and shareholder of Ampet, Inc. He has also served as the President, a Director and Chief Operating Officer of Chippewa Resources Corporation from July of 1990 through March 1993 when he resigned after a change of control. Mr. Parker also serves as President, Chief Executive Officer and Director of Amber. He received a Bachelor of Science in Mineral Land Management from the University of Colorado in 1983. He is a member of the Rocky Mountain Oil and Gas Association and is a board member of the Independent Producers Association of the Mountain States (IPAMS). He also serves on other boards including Community Banks of Colorado.

Aleron H. Larson, Jr. has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. Mr. Larson served as the Chairman, Secretary, CEO and a Director of Chippewa Resources Corporation, a public company then listed on the American Stock Exchange from July 1990 through March 1993 when he resigned after a change of control. Mr. Larson serves as Chairman of the Board, Secretary and Director of Amber Resources Company (“Amber”), a public oil and gas company which is our majority-owned subsidiary. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970.

Kevin K. Nanke, Treasurer and Chief Financial Officer, joined Delta in April 1995. Since 1989, he has been involved in public and private accounting with the oil and gas industry. Mr. Nanke received a Bachelor of Arts in Accounting from the University of Northern Iowa in 1989. Prior to working with us, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA’s and the Council of Petroleum Accounting Society.

John R. Wallace, Executive Vice President, Exploration and Chief Operating Officer, joined Delta in October 2003. Mr. Wallace was Vice President of Exploration and Acquisitions for United States Exploration, Inc. (“USX”), a publicly-held oil and gas exploration company, from May 1998 to October 2003, when he became employed by Delta. For more than five years prior to joining USX, Mr. Wallace was President of The Esperanza Corporation, a privately held oil and gas acquisition company, and Vice President of Dual Resources, Inc., a privately held oil and gas exploration company. Esperanza effected more than 25 acquisitions of producing properties throughout the United States. In addition, Esperanza formed and administered royalty programs for private investors, primarily in the Rocky Mountain region, and has participated in a number of international exploration projects. Dual Resources is in the business of engineering and selling exploration prospects, several of which have resulted in new field discoveries. Mr. Wallace is the son of John B. Wallace, a Director of the Company.

Jerrie F. Eckelberger is an investor, real estate developer and attorney who has practiced law in the State of Colorado since 1971. He graduated from Northwestern University with a Bachelor of Arts degree in 1966 and received his Juris Doctor degree in 1971 from the University of Colorado School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with the Eighteenth Judicial District Attorney’s Office in Colorado. From 1975 to present, Mr. Eckelberger has been engaged in the private practice of law and is presently a member of the law firm of Eckelberger & Jackson, LLC. Mr. Eckelberger previously served as an officer, director and corporate counsel for Roxborough Development Corporation. Since March, 1996, Mr. Eckelberger has engaged in the investment and development of Colorado real estate through several private companies in which he is a principal.

James B. Wallace has been involved in the oil and gas business for over 40 years and has been a partner of Brownlie, Wallace, Armstrong and Bander Exploration in Denver, Colorado since 1992. From 1980 to 1992 he was Chairman of the Board and Chief Executive Officer of BWAB Incorporated. Mr. Wallace currently serves as a member of the Board of Directors and formerly served as the Chairman of Tom Brown, Inc., an oil and gas exploration company then listed on the New York Stock Exchange. He received a B.S. Degree in Business Administration from the University of Southern California in 1951. James B. Wallace is the father of John R. Wallace, the Executive Vice President, Exploration and Chief Operating Officer of Delta.

Joseph L. Castle II has been a Director of Castle Energy Corporation (“Castle”) since 1985. Mr. Castle is the Chairman of the Board of Directors and Chief Executive Officer of Castle, having served as Chairman from December 1985 through May 1992 and since December 20, 1993. Mr. Castle also served as President of Castle from December 1985 through December 20, 1993, when he reassumed his position as Chairman of the Board. Previously, Mr. Castle was Vice President of Philadelphia National Bank, a corporate finance partner at Butcher and Sherrerd, an investment banking firm, and a Trustee of The Reading Company. Mr. Castle has worked in the energy industry in various capacities since 1971. Mr. Castle is also a director of Comcast Corporation and Charming Shoppes, Inc. Since May of 2000, Mr. Castle has served as the Chairman of the Board of Trustees of the Diet Drug Products Liability (“Phen-Fen”) Settlement Trust.

Russell S. Lewis has been a director of Castle since April 2000. From 1994 to 1999, Mr. Lewis was the Chief Executive Officer of TransCore, Inc., a company which sells and installs electronic toll collection systems. Since 1999, Mr. Lewis has been the owner and President of Lewis Capital Group, a company investing in and providing consulting services to growth-oriented companies. Since March 2000, Mr. Lewis has also been Senior Vice President of Corporate Development at VeriSign, Inc. In February of 2002, Mr. Lewis joined VeriSign full-time as Executive Vice President and General Manager of VeriSign’s Global Registry Services Group, which maintains the authoritative database for all “.com,” “.net” and “.org” domain names in the Internet.

John P. Keller has been a director of Castle since April 1997. Since 1972, Mr. Keller has served as the President of Keller Group, Inc., a privately-held corporation with subsidiaries in Ohio, Pennsylvania and Virginia. In 1993 and 1994, Mr. Keller also served as the Chairman of American Appraisal Associates, an appraisal company. Mr. Keller is also a director of A.M. Castle & Co.

Messrs. Castle, Lewis and Keller were proposed for appointment to the board by Castle Energy Corporation pursuant to the Purchase and Sale Agreement between Delta and Castle Energy Corporation which had an effective date of October 1, 2001. Messrs Castle, Lewis and Keller are also directors of Castle Energy Corporation.

As of September 7, 2004, Messrs. Castle, James B. Wallace and Eckelberger served as the Incentive Plan Committee and as the Compensation Committee. Messrs. Lewis, Keller, Eckelberger and James B. Wallace served as the Audit Committee; and Messrs Lewis, Castle and James B. Wallace served as the Nominating Committee.

All of our officers will hold office until the next annual directors’ meeting. There is no arrangement or understanding among or between any such officers or any persons pursuant to which such officer is to be selected as one of our officers.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Delta’s common stock currently trades under the symbol “DPTR” on the NASDAQ National Market. The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

The number of holders of record of our Common Stock at September 7, 2004 was approximately 1,000 which does not include an estimated 2,600 additional holders whose stock is held in “street name.”

We have not paid dividends on our stock and we do not expect to do so in the foreseeable future.

On April 23, 2004, we issued a total of 1,525,000 shares of our common stock in connection with the execution of an amendment to an existing Purchase and Sale Agreement with Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”) that was initially dated August 1, 2003. In connection with this transaction we relied on the exemption provided by Section 4(2) of the Securities Act of 1933. We reasonably believe that both of the investors are “Accredited Investors” as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act of 1933 at the time the transactions occurred. The investors acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to the investors, and stop transfer orders were given to our transfer agent.

In June 2004, we issued a total of 6,000,000 shares of our common stock to 51 Accredited Investors in a private placement. The shares were sold for $12 per share for an aggregate of $72 million. In connection with the private placement we paid Sterne, Agee & Leach, Inc., the placement agent, a commission of $3.6 million. In connection with this offering we relied on the exemptions provided by Section 4(2) of the Securities Act of 1933 and Rule 506 of Regulation D promulgated under the Securities Act of 1933. We reasonably believe that all of the investors are “Accredited Investors” as such term is defined in Rule 501 of Regulation D at the time the offering occurred. The investors acquired the shares for investment purposes. Restrictive legends were placed on the certificates issued to the investors, and stop transfer orders were given to our transfer agent. A Form D reporting the offering was filed with the Securities and Exchange Commission.

We did not repurchase any of our shares of common stock during the quarter ended June 30, 2004.

The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Liquidity is a measure of a company’s ability to access cash. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, and through cash provided by operating activities and sale of oil and gas properties. During fiscal 2004, we increased our credit facility to $100 million with an available borrowing base of $69.4 million and raised approximately $98 million in additional capital through the sale of our common stock. The prices we receive for future oil and natural gas production and the level of production have significant impacts on operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production.

We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, the sales of non-strategic assets, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.

We believe that borrowings under the Revolving Credit Facility, projected operating cash flows and cash on hand will be sufficient to meet the requirements of our business. However, future cash flows are subject to a number of variables including the level of production and oil and natural gas prices. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to, drilling results, product pricing and future acquisition and divestitures of properties.

We continue to evaluate potential acquisitions and property development opportunities. During fiscal 2004, we completed the following transactions.

On June 29, 2004, we acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc (“Alpine”) for a total purchase price of $120.6 million, net of a $1.9 million downward purchase price adjustment. Alpine was a privately held exploration and production company, active primarily in South East Texas and Louisiana.

On April 21, 2004, we acquired a fifty percent interest in approximately 1,300 leasehold acres in the Midway Loop Project located in Polk County, Texas from Wilsource Enterprises, LLC for $340,000 and 31,250 shares of the Company’s common stock valued at $289,000.

Also on April 21, 2004, we acquired a seventy five percent interest in approximately 9,800 leasehold acres in the Divide Creek Extension Project located in Mesa County, Colorado from Wilsource Enterprises, LLC for $90,000 in cash and 187,500 shares of the Company’s common stock valued at $1.7 million.

In March 2004, we acquired a 50% interest in Big Dog Drilling Company, LLC (“BDDC”) for an initial investment of approximately $3 million. Also in March 2004, we purchased a 50% interest in Shark Trucking Company, LLC (“STC”) for an initial investment of approximately $276,000. The remaining 50% interest in both BDDC and STC is owned by Mike Davis. STC’s primary assets include the ownership of trucking equipment used for the mobilization of drilling rigs and equipment.

The drilling rigs owned by BDDC and trucking company will be used primarily for drilling activities on Delta’s properties. Increasing drilling rig rates, periodic lack of availability of drilling rigs and increased drilling by us were contributing factors to this venture.

On February 26, 2004, we acquired approximately 135,000 leasehold acres in the Columbia River Basin project in eastern Washington from an unrelated entity for $1.4 million in cash. We will become the operator once drilling begins on this acreage.

On February 24, 2004, we acquired certain properties in Texas from Labyrinth Enterprises, LLC, an unrelated entity, for $1.5 million in cash and 185,000 shares of our common stock valued at $1.6 million.

On December 10, 2003, we completed an acquisition of certain production and acreage located primarily in Eland and Stadium fields in Stark County, North Dakota, from Sovereign Holdings, LLC, a privately - held Colorado limited liability company (“Sovereign”), pursuant to the terms of a Purchase and Sale Agreement effective as of December 1, 2003. The total consideration paid for these properties was 773,500 shares of our common stock valued at $4.2 million, net of normal closing adjustments.

On September 19, 2003, we completed an acquisition of certain producing and drilling prospects in Colorado (the “South Tongue Prospect”) and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”). On the date of acquisition, we estimated proved reserves to be approximately 4.7 Bcfe. The acquisition included approximately 100,000 acres of prospect leases in the South Tongue and 20,000 acres of prospect leases in Wyoming. The total consideration was $13.1 million net of normal closing adjustments. Subsequent to September 19, 2003, we increased our South Tongue acreage position to approximately 260,000.

On April 22, 2004, we amended our agreement with Davis to, among other things, add certain oil and gas leases located in Colorado known as the “North Tongue Prospect,” decrease the amount of Davis’s reversionary working interest after payout in the properties acquired under the initial agreement from 50% to 42.5%, change the definition of payout, change certain drilling obligations and modify our obligation to issue additional shares of stock to Davis upon the designation of Bonus Prospects. The initial consideration required to be paid to Davis upon execution of the Amended Agreement was 1,525,000 shares of our common stock, valued at $17.3 million. The entire amount was allocated to unproved undeveloped properties.

During the current fiscal year, we agreed to invest an aggregate of $1 million for a 6.25% interest as a member of an unaffiliated Delaware limited liability company that is currently in the process of attempting to obtain the rights to own and operate a liquid natural gas facility from an existing platform located offshore California. If the limited liability company is successful in obtaining these rights, it intends to engage in the business of accepting and vaporizing liquid natural gas delivered by liquid natural gas tankers, transporting the vaporized liquid natural gas through proprietary gas pipelines and selling the vaporized natural gas to third party customers located in California. As of the date of this Report, the limited liability company had not yet engaged in any revenue producing activities. We have accounted for our investment at cost.

Our cashflow from operating activities increased 20% to $9.6 million for the year ended June 30, 2004 compared to $8 million for the same period a year earlier, primarily as a result of an increase in net income.

Our capital and exploration expenditures and sources of financing for the years ended June 30, 2004, 2003 and 2002 are as follows:

We anticipate our capital and exploration expenditures to range between $60 and $80 million for fiscal 2005. The timing of most of our capital expenditures is discretionary. We have one drilling commitment in Washington County, Colorado as is discussed below.

On March 31, 2004, we completed the sale of all of our Pennsylvania properties to Castle Energy Corporation, a 20% shareholder of us at June 30, 2004, for cash consideration of $8 million, which we believe is fair value, with an effective date of January 1, 2004 and resulted in a gain on sale of oil and gas properties of $1.9 million.

Subsequent to year-end on August 19, 2004, we completed the sale of our interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $19.3 million. We paid $8.8 million of our credit facility balance from the sale of these properties. No gain or loss was recognized.

Our borrowing base, which determines the amounts that we are allowed to borrow or have outstanding under our credit facility, is $69.4 million as of June 30, 2004. Subsequent determinations of our borrowing base will be made by the lending banks at least semi-annually on October 1 and April 1 of each year or as unscheduled redeterminations. In connection with each determination of our borrowing base, the banks will also redetermine the amount of our monthly commitment reduction. We do not currently have any monthly commitment reduction obligation as a result of our most recent redetermination, and we will not have any monthly commitment reduction obligation until it is redetermined by our banks. Our borrowing base and the revolving commitment of the banks to lend money under the credit agreement must be reduced as of the first day of each month by an amount determined by the banks under our credit agreement. The amount of the borrowing base must also be reduced from time to time by the amount of any prepayment that results from our sale of oil and gas properties. If, as a result of any such monthly commitment reduction or reduction in the amount of our borrowing base, the total amount of our outstanding debt were to exceed the amount of the revolving commitment then in effect, then, within 30 days after we are notified by the Bank of Oklahoma, we would be required to make a mandatory prepayment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base. If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit agreement.

For so long as the revolving commitment is in existence or any amount is owed under any of the loan documents, we will also be required to comply with loan covenants that will limit our flexibility in conducting our business and which could cause us significant problems in the event of a downturn in the oil and gas market. If an event of default occurs and continues after the expiration of any cure period that is provided for in our credit agreement, the entire principal amount due under the loan documents, all accrued interest and any other liabilities that we might have to the lending banks under the loan documents will all become immediately due and payable, all without notice of default of any kind. The foregoing information is provided to alert investors that there is risk associated with our existing debt obligations. It is not intended to provide a summary of the terms of our agreements with our lenders.

We have entered into an agreement with Edward Mike Davis which requires us to drill not less than ten prospects to the J-Sand formation during every twelve month period in our area of mutual interest in Washington County, Colorado. The estimated cost to drill a J-Sand formation prospect approximates $225,000. We successfully completed our drilling commitments for fiscal 2004. We will be required to spend approximately $2.3 million during fiscal 2005.

Our abandonment retirement obligation arises from the plugging and abandonment liabilities for our oil and gas wells. The majority of this obligation will not occur over the next five years.

Our corporate office in Denver, Colorado is under an operating lease which will expire in fiscal 2009. Our average yearly payments approximate $310,000. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment.

The following discussion and analysis relates to items that have affected our results of operations for the three years ended June 30, 2004, 2003 and 2002. This analysis should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-K.

Net income. Net income increased $3.8 million to $5.1 million for fiscal 2004, an increase of 290% as compared to $1.3 million for fiscal 2003. This increase was primarily due to a 40% increase in production from fiscal 2003 relating to acquisitions completed during fiscal 2004 and 2003, the development of undeveloped properties associated with these acquisitions and an increase in average oil and natural gas prices received by Delta.

Revenue. During fiscal 2004, oil and natural gas revenue from continuing operations increased 65% to $37.2 million, as compared to $22.6 million in fiscal 2003. The increase was the result of (i) an average onshore gas prices received in fiscal 2004 of $5.27 per Mcf compared to $4.71 per Mcf in 2003, (ii) an increase in average onshore oil price received in fiscal 2004 of $33.09 per Bbl compared to $28.82 per Bbl in 2003, (iii) a slight increase in offshore oil price received of $22.11 per Bbl in fiscal 2004 compared to $20.21 in 2003 and (iv) a 40% increase in average daily production during the fiscal year previously discussed above.

Cash payments required on our hedging activities impacted revenues in 2004 and 2003. The cost of settling of our hedging activities was $859,000 in fiscal 2004 and $1.9 million in fiscal 2003.

Production volumes, average prices received and cost per equivalent Mcf for the years ended June 30, 2004 and 2003 are as follows:

Production Costs. Production costs increased 16% to $9.8 million for fiscal 2004, as compared to $8.4 million for 2003. However, production costs per equivalent Mcf decreased from $1.35 per Mcf equivalent in fiscal 2003 to $1.06 per Mcf equivalent in fiscal 2004. This decrease in production cost per Mcf equivalent can primarily be attributed to our Padget Field acquisition completed during fiscal 2003. The Padget Field added an additional 1.2 Bcf equivalent to current year production with an associated cost of $.22 per Mcf equivalent.

Drilling and Trucking Operations. In March 2004, we acquired a 50% interest in both the Big Dog Drilling Company and Shark Trucking Company. We began drilling our first well with a Big Dog Drilling Company rig in August 2004 and will primarily drill on our acreage. The cost associated with these two entities represents start up costs incurred through year end.

Depreciation and Depletion Expense. Depreciation and depletion expense increased 96% to $9.9 million in fiscal 2004, as compared to $5 million in fiscal 2003. Depreciation and depletion expenses per equivalent Mcf for our onshore properties increased to $1.46 per Mcf equivalent during fiscal 2004 from $1.02 per Mcf equivalent in fiscal 2003. This increase can be attributed to the acquisition of our Christensen Field in Washington County which had a depreciation and depletion expense of $2.40 per Mcf equivalent and the acquisition of our Eland and Stadium fields which had a depreciation and depletion expense of $2.74 per Mcf equivalent.

Dry Hole Costs. We incurred dry hole costs of $2.1 million on five exploratory wells in fiscal 2004 and $537,000 on three exploratory wells in fiscal 2003.

Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Our exploration costs for fiscal 2004 of $2.4 million included an extensive 78 square mile seismic shoot in Washington County, Colorado on our South Tongue Prospect. Currently, we are obtaining seismic information on a 22.75 square miles in Washington County, Colorado on our North Tongue Prospect and will be expanding our South Tongue Prospect shoot to include a 75 square mile shoot during fiscal 2005.

Professional Fees. Professional fees include corporate legal costs, accounting fees, shareholder relations consultants and legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to our undeveloped offshore California leases. Our professional fees increased 43% to $1.2 million for fiscal 2004, as compared to $842,000 for fiscal 2003. The increase in professional fees can attributed largely to the compliance with the Sarbanes-Oxley Act.

General and Administrative Expenses. General and administrative increased 60% to $6.9 million in fiscal 2004, as compared to $4.3 million in fiscal 2003. The increase in general and administrative expenses is primarily attributed to (i) the increase in technical and administrative staff and related personnel costs, (ii) the expansion of our office facility and (iii) additional bonuses earned by officers and management.

Interest and Financing Costs. Interest and financing costs remained consistent with fiscal 2003. We expensed $1.8 million for both fiscal 2004 and 2003. The decrease in interest rates during fiscal 2004 was offset by the increase in long-term debt obligations during the year.

Discontinued Operations. Included in discontinued operations are (i) income (loss) from operations of properties sold and (ii) gain (loss) on sale of oil and gas properties. We are required to re-class related revenue and expenses relating to sales of our oil and gas properties for all periods presented. During fiscal 2004, we sold our Pennsylvania properties which resulted in a gain on sale of $1.9 million. During fiscal 2003, we sold some non-strategic oil and gas properties which resulted in a gain of $277,000.

Net Income (Loss). Our net income for the year ended June 30, 2003 was $1.3 million compared to net loss of $6.3 million for the year ended June 30, 2002. The results for the years ended June 30, 2003 and 2002 were affected by the items described in detail below.

Revenue. Total revenue for the year ended June 30, 2003 was $20.7 million compared to $8 million for the year ended June 30, 2002. Oil and gas sales from continuing operations for the year ended June 30, 2003 were $22.6 million compared to $8 million for the year ended June 30, 2002. The increase in oil and gas sales during the year ended June 30, 2003 resulted primarily from the Castle and Piper acquisitions, completed in fiscal 2002.

Production volumes and average prices received for the years ended June 30, 2003 and 2002 are as follows:

Production Costs. Production costs from continuing operations for the year ended June 30, 2003 were $8.4 million compared to $4.3 million for the year ended June 30, 2002. Production costs from continuing operations decreased slightly compared to 2002 as a result of less non-capitalized workover costs incurred during fiscal 2003 compared to fiscal 2002. On a per Mcf equivalent basis, production costs from continuing operations were $1.35 for onshore properties and $2.40 for offshore properties during the year ended June 30, 2003 compared to $.90 for onshore properties and $1.94 for offshore properties for the year ended June 30, 2002. The change in production costs per Mcf equivalent fluctuates with the nature of the properties, including maturity and non-capitalized workover costs. The acquisition of the Padget field in Kansas was the primary contributor to lowering our production cost per Mcf.

Depreciation and Depletion Expense. Depreciation and depletion from continuing operations expense for the year ended June 30, 2003 was $5 million compared to $3.3 million for the year ended June 30, 2002. On a Mcf equivalent basis, the depletion rate was $1.02 for onshore properties and $.79 for offshore properties during the year ended June 30, 2003 compared to $1.58 for onshore properties and $.69 for offshore properties for the year ended June 30, 2002.

Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Exploration expenses were $140,000 for the year ended June 30, 2003 compared to $155,000 for the year ended June 30, 2002.

Abandonment and Impaired Oil and Gas Properties. We recorded an expense for the abandonment and impairment of oil and gas properties for the year ended June 30, 2002 of $1.5 million. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $-0- and $878,000 for the years ended June 30, 2003 and 2002, respectively. Also during fiscal 2002, we recorded an impairment of $602,000 attributable to our undeveloped properties as future development of these properties are unlikely. We made a determination based on the political risk and lack of expertise in the area that it would not be economical to develop this prospect and as such we may not proceed with this prospect.

Professional Fees. Professional fees for the year ended June 30, 2003 were $842,000 compared to $1.3 million for the year ended June 30, 2002. Professional fees include corporate legal costs, accounting fees and shareholder relations consultants.

General and Administrative Expenses. General and administrative expenses for year ended June 30, 2003 were $4.3 million compared to $2 million for the year ended June 30, 2002. The increase in general and administrative expenses is primarily attributed to increased costs in anticipation of the acquisitions completed in fiscal 2003 including office relocation and additional staff.

Interest and Financing Costs. Interest and financing costs for the year ended June 30, 2003 were $1.8 million compared to $1.3 million for the year ended June 30, 2002. The increase in interest and financing costs can be attributed to the increase in debt related to the Castle acquisition, which closed on May 31, 2002.

Discontinued Operations. Included in discontinued operations are (i) income (loss) from operations of properties sold and (ii) gain (loss) on sale of oil and gas properties. We are required to re-class related revenue and expenses relating to sales of our oil and gas properties for all periods presented. During fiscal 2003, we sold some non-strategic oil and gas properties which resulted in a gain of $277,000. During fiscal 2002, we sold non-strategic oil and gas properties which resulted in a loss on sale of $88,000.

The discussion and analysis of our financial condition and results of operations were based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Gas and oil lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine that proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our developed proved properties and compare such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the recorded book values associated with gas and oil properties. As a result of our review, we recognized an impairment of $1.5 million for the year ended June 30, 2002. We did not record a impairment during the years ended June 30, 2004 and June 2003.

We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize future contracts, swaps or options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive.

On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management (CPRM) activities.

In January 2003, the FASB issued Financial Interpretation No. 46, “Consolidation of Variable Interest Entities - an interpretation of ARB No. 51” (“FIN 46”). FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (“VIE’s”). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights. Such entities are known as VIE’s. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both.

An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003 to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time, we do not have an interest in an unconsolidated VIE.

Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency exchange and interest rate risks and do not hold or issue financial instruments to any degree for trading purposes. All of our revenue and related receivables are payable in U.S. dollars.

Beginning in fiscal 2003, we began to hedge a portion of our oil and gas production using swap and collar agreements. The purpose of these hedge agreements is to provide a measure of stability to our cash flow in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. There were no derivative contracts outstanding at June 30, 2004.

We were subject to interest rate risk on $69.4 million of variable rate debt obligations at June 30, 2004. The annual effect of a ten percent change in interest rates would be approximately $350,000. The interest rate on these variable rate debt obligations approximates current market rates as of June 30, 2004.

Financial Statements are included and begin on page F-1. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management’s control objectives.

With the participation of management, our chief executive officer and chief financial officer evaluated the effectiveness of the design and operation of our disclosure controls and procedures at the conclusion of the period ended June 30, 2004. Based upon this evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that we file with the Securities and Exchange Commission.

There were no significant changes in our internal controls or, to the knowledge of our management, in other factors that could significantly affect internal controls subsequent to the date of most recent evaluation of our disclosure controls and procedures utilized to compile information included in this filing.

The information required by Part III, Item 10 “Directors and Executive Officers of the Registrant,” Item 11 “Executive Compensation,” Item 12 “Security Ownership of Certain Beneficial Owners and Management,” Item 13 “Certain Relationships and Related Transactions” and Item 14 “Principal Accounting Fees and Services” is incorporated by reference to the Company’s definitive Proxy Statement which will be filed with the Securities and Exchange Commission in connection with the 2004 Annual Meeting of Shareholders. For information concerning Item 10 “Directors and Executive Officers of the Registrant,” see Part I – Directors and Executive Officers.

(a)(3) Exhibits. The Exhibits listed in the Index to Exhibits appearing at page 46 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with a “*”.

(b) Reports on Form 8-K. During the quarter ended June 30, 2004, the Registrant filed Reports on Form 8-K during the last quarter covered by this Report as follows:

We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation and subsidiaries as of June 30, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Petroleum Corporation and subsidiaries as of June 30, 2004 and 2003, and the results of their operations and their cash flows for each of the years then ended in conformity with accounting principles generally accepted in the United States of America.

As described in Note 2 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations as of July 1, 2002.

Delta Petroleum Corporation (“Delta”) was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The Company owns interests in developed and undeveloped oil and gas properties in federal units offshore California, near Santa Barbara, and developed and undeveloped oil and gas properties in the continental United States.

At June 30, 2004 the Company owned 4,277,977 shares of the common stock of Amber Resources Company (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company that owns undeveloped oil and gas properties in federal units offshore California, near Santa Barbara.

On February 19, 2002, the Company acquired 100% of the outstanding shares of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Piper was merged into a subsidiary wholly owned by Delta.

The Company’s results of operations are substantially dependent on the price received for its crude oil and natural gas products and the results of our exploration and development activities. Prices for these products are subject to fluctuations in response to changes in supply, market uncertainty and political instability.

The consolidated financial statements include the accounts of Delta, Amber and Piper (collectively, the Company). All intercompany balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods. Certain reclassifications have been made to amounts reported in previous years to conform to the 2004 presentation.

In March 2004, the Company acquired a 50% interest in Big Dog Drilling, LLC (“BDDC”) and a 50% interest in Shark Trucking Company, LLC (“STC”). Delta controls both entities and has consolidated the activities of both BDDC and STC in 2004. The results of operations and minority interest were not significant.

Cash equivalents consist of money market funds. The Company considers all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.

The Company classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards No. 115 (SFAS 115), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income. At the time securities are sold or otherwise disposed of, gains or losses are included in earnings.

Inventories consist of pipe, other production equipment and natural as placed in storage. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of June 30, 2004 and 2003, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is charged to expense. If the unproved properties are determined to be productive, the related costs are transferred to proved gas and oil properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss.

Depreciation and depletion of capitalized acquisition, exploration and development costs is computed on the units-of-production method by individual fields as the related proved reserves are produced.

Other property and equipment are recorded at cost or estimated fair value upon acquisition and depreciated using the straight-line method over their estimated useful lives.

Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements. Partnership net assets represent the Company’s share of net working capital in such entities.

Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144) requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS No. 144 are permanent and may not be restored in the future.

The Company assesses developed properties on an individual field basis for impairment on at least an annual basis. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company recorded no impairment provision attributable to certain producing properties for the years ended June 30, 2004 and 2003 and $878,000 for the year ended June 30, 2002.

For undeveloped properties, the need for an impairment reserve is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the undeveloped property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded no impairment provision attributable to certain undeveloped properties for the years ended June 30, 2004, 2003 and 2002.

In addition, the Company recorded an impairment provision attributed to certain undeveloped foreign properties of $602,000 for the year ended June 30, 2002 and had no similar foreign impairment for the years ended June 30, 2004 and 2003.

In July 2001, the Financial Accounting Standards Board approved for issuance SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years of $20,000, net of tax effects, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller. The following is a reconciliation of the Company’s asset retirement obligations for the years ended June 30, 2004 and 2003.

The pro forma effects of the application of SFAS No. 143 on net income would have been immaterial and there would have been no effect on earnings per share.

The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company primarily utilizes future contracts, swaps or options which are generally placed with major financial institutions or with counterparties of high credit quality that the Company believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural futures which have a high degree of historical correlation with actual prices received by the Company

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of Other Comprehensive Income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings.

At June 30, 2004, the Company had no outstanding derivative financial instruments. At June 30, 2003, the Company had a current derivative liability and a corresponding accumulated other comprehensive loss of $468,000.

The Company accounts for its stock option plans in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. In December, 2002 the FASB issued SFAS No. 148, “Accounting for Stock-based Compensation-Transition and Disclosure.” SFAS 148 amends FASB Statement No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 has no material impact on the Company, as we do not plan to adopt the fair-value method of accounting for stock options at the current time. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common stock.

Had compensation cost for the Company’s stock-based compensation plan been determined using the fair value of the options at the grant date, the Company’s net income (loss) for the years ended June 30, 2004, 2003 and 2002 would have been as follows:

The Company uses the asset and liability method of accounting for income taxes as set forth in Statement of Financial Accounting Standards No. 109 (SFAS No. 109), Accounting for Income Taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options and warrants. The effect of potentially dilutive securities outstanding was antidilutive during year ended June 30, 2002.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include oil and gas reserves, bad debts, oil and gas properties, depletion and impairment, marketable securities, income taxes, derivatives, asset retirement obligations, contingencies and litigation. Actual results could differ from these estimates.

The Company has ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $10.8 million and $10.2 million at June 30, 2004 and 2003, respectively. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company’s investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties as discussed herein.

The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company’s size, it would be difficult for the Company to proceed with exploration and development plans should other substantial interest owners elect not to proceed. However, to the best of its knowledge, the Company believes the designated operators and other major property interest owners intend to proceed with exploration and development plans under the terms and conditions of the operating agreement.

The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service (MMS) of the U.S. Federal Government whereby as long as the owners of each property were progressing toward defined milestone objectives, the owners’ rights with respect to the properties continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.

On June 22, 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the MMS does not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act (“CZMA”), and ordered the MMS to set aside its approval of the suspensions of the Company’s offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of California with the required consistency determination. No such consistency determination has as yet been made.

The delays have prevented the property owners from submitting for approval an exploration plan on four of the properties. If and when plans are submitted for approval, they are subject to review for consistency with the CZMA, and by the MMS for other technical requirements.

Even though the Company is not the designated operator of the properties and regulatory approvals have not been obtained, the Company believes exploration and development activities on these properties will occur and is committed to expend funds attributable to its interests in order to proceed with obtaining the approvals for the exploration and development activities.

Based on the preliminary indicated levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair value of its property interests are in excess of their carrying value at June 30, 2004 and June 30, 2003 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.

The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the CZMA and the Company decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear the Company’s appeal of any such ruling or ultimately makes an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time.

As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, and the leases are still valid. If the leases are found not to be valid for some reason, or if the United States either does not comply with the order requiring it to make a consistency determination or finds that development is inconsistent with the CZMA, it would appear that the leases would become impaired even though the Company would undoubtedly proceed with its litigation. It is also possible that other events could occur that would cause the leases to become impaired, and the Company will continuously evaluate those factors as they occur.

On January 9, 2002, the Company and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of the Company’s Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the Norton case that a 1990 amendment to the CZMA required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued.

The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. The Company’s claim for lease bonuses and rentals paid by it and its predecessors is in excess of $152 million. In addition, The Company’s claim for exploration costs and related expenses will also be substantial. In the event, however, that the Company receives any proceeds as the result of such litigation, it will be obligated to pay a portion of any amount received by it to landowners and other owners of royalties and similar interests, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties.

On June 29, 2004, the Company acquired substantially all of the oil and gas assets owned by several entities controlled by Alpine Resources, Inc (“Alpine”) for a total purchase price of $120.6 million, net of a $1.9 million downward purchase price adjustment, which reflect the net revenues after operating costs and related acquisition costs from the effective date of June 1, 2004 through closing at June 29, 2004. Alpine was a privately held exploration and production company, active primarily in South East Texas and Louisiana. Based on a preliminary valuation assessment, the total acquisition cost was allocated $38 million to proved developed producing, $73.9 million to proved undeveloped and $8.7 to unproved properties. See sale of oil and gas properties in Note 15.

On September 19, 2003, the Company completed an acquisition of certain producing and drilling prospects in Colorado (the “South Tongue Prospect”) and Wyoming from Edward Mike Davis LLC and Edward Mike Davis, individually (collectively, “Davis”), pursuant to the terms of a Purchase and Sale Agreement effective as of August 1, 2003. The total consideration paid for these properties was 1,000,000 shares of the Company’s common stock, $8 million, of which $2 million was paid in cash and $6 million in the form of a short-term promissory note payable that was paid on October 3, 2003 and 26,000 shares of the Company’s common stock to an unrelated individual who introduced the two parties. The shares issued were recorded at a price of $5.15 per share, a five day average surrounding the announcement of the transaction. The Company recorded an upward purchase price adjustment of approximately $220,000 which reflects the operating and acquisition related costs in excess of net revenue from the effective date of August 1, 2003 through the closing date of September 19, 2003. The total acquisition cost of $13.1 million was allocated between proved developed producing of $5.2 million and unproved undeveloped of $7.9 million based on preliminary information.

On April 22, 2004, the Company amended its agreement with Davis to, among other things, add certain oil and gas leases located in Colorado known as the “North Tongue Prospect,” decrease the amount of Davis’s reversionary working interest after payout in the properties acquired under the initial agreement from 50% to 42.5%, change the definition of payout, change certain drilling obligations and modify the Company’s obligation to issue additional shares of stock to Davis upon the designation of Bonus Prospects. The initial consideration required to be paid to Davis upon execution of the Amended Agreement was 1,525,000 shares of the Company’s common stock, valued at $17.3 million. The entire amount was allocated to unproved undeveloped properties.

The amended agreement eliminates the Company’s obligation to issue shares for Bonus Prospects that existed under the initial agreement with respect to the South Tongue Prospect, but it added a new obligation to issue additional shares for Bonus Prospects that are designated with respect to the North Tongue Prospect. With regard to the North Tongue Prospect only, for any prospect that is identified at any time after drilling, coring, testing and logging to contain in combination from specified formations at least one million barrels of recoverable oil or six billion cubic feet of recoverable gas or a combination of oil or gas equal to or exceeding one million barrels of oil equivalent using a six million cubic feet to one barrel gas-to-oil ratio, as determined by independent engineers, then such acreage is required to be designated as a “Bonus Prospect.”

Upon designation of a Bonus Prospect, the Company is required to issue to Davis as additional purchase price, up to 190,000 shares of the Company’s common stock, or such lesser amount so that the value of such stock based upon the average closing price of the stock for the immediately preceding 30-day period may equal but does not exceed $950,000, for each Bonus Prospect (a “Bonus”). This requirement applies only to the North Tongue Prospect and is limited to a maximum of five Bonus Prospects. No Bonus or additional shares are payable for prospects located on the South Tongue Prospect, regardless of potential or ultimate production. The Company is obligated to file additional registration statements at the Company’s expense covering the re-sale of each issuance of shares for each Bonus Prospect designation.

The following unaudited pro forma consolidated statements of operations information assumes that the Alpine and Davis property acquisitions occurred as of July 1, 2002:

The above unaudited adjusted Pro Forma Consolidated Statements of Operations, based on the historical producing property operating results of Alpine, Davis and Delta’s adjusted for Delta’s proforma depletion, an estimate of additional administrative costs and approximately $3 million of pro forma income tax expense in 2004 are not necessarily indicative of the results of operations if Delta would have acquired the Alpine and Davis properties at July 1, 2002.

On December 10, 2003, the Company completed an acquisition of certain production and acreage located primarily in Eland and Stadium fields in Stark County, North Dakota, from Sovereign Holdings, LLC, a privately - held Colorado limited liability company (“Sovereign”), pursuant to the terms of a Purchase and Sale Agreement effective as of December 1, 2003. The total consideration paid for these properties was 773,500 shares of the Company’s common stock. The shares issued were recorded at a price of $5.58, a five day average surrounding the closing of the transaction. The Company recorded a downward purchase price adjustment of approximately $84,000 which reflects the operating and acquisition related costs in excess of net revenue from the effective date of December 1, 2003 through the closing date of December 5, 2003. The total acquisition cost of $4.2 million was allocated to proved developed producing properties.

On February 24, 2004, the Company acquired certain properties in Texas from Labyrinth Enterprises, LLC, an unrelated entity, for $1.5 million in cash and 185,000 shares of the Company’s common stock valued at $1.6 million based on a five day average surrounding the closing of the transaction.

On February 26, 2004, the Company acquired approximately 135,000 leasehold acres in the Columbia River Basin project in eastern Washington from an unrelated entity for $1.4 million in cash. The Company will become the operator once drilling begins on this acreage. Subsequent to the quarter end, the Company purchased approximately 23,000 additional net acreage in this project through State and Federal lease sales.

In March 2004, the Company acquired a 50% interest in Big Dog Drilling Company, LLC (“BDDC”) for an initial investment of approximately $3 million. The remaining interest is owned by Davis. BDDC’s primary assets include two drilling rigs rated at drilling depths of up to 10,000 feet and certain additional drilling equipment.

Also in March 2004, the Company acquired a 50% interest in Shark Trucking Company, LLC (“STC”) for an initial investment of approximately $276,000. STC has a similar ownership structure to that of BDDC. STC’s primary assets include the ownership of trucking equipment used for the mobilization of drilling rigs and equipment.

The drilling rigs and trucking company will be used primarily for drilling activities on Delta’s properties. Increasing drilling rig rates, periodic lack of availability of drilling rigs and increased drilling by Delta were contributing factors to this venture.

On April 21, 2004, the Company acquired a fifty percent interest in approximately 1,300 leasehold acres in the Midway Loop Project located in Polk County, Texas from Wilsource Enterprises, LLC for $340,000 and 31,250 shares of the Company’s common stock valued at $289,000.

Also on April 21, 2004, the Company acquired a seventy five percent interest in approximately 9,800 leasehold acres in the Divide Creek Extension Project located in Mesa County, Colorado from Wilsource Enterprises, LLC for $90,000 in cash and 187,500 shares of the Company’s common stock valued at $1.7 million.

During the current fiscal year, the Company agreed to invest an aggregate of $1 million for a 6.25% interest as a member of an unaffiliated Delaware limited liability company that is currently in the process of attempting to obtain the rights to own and operate a liquid natural gas facility from an existing platform located offshore California. If the limited liability company is successful in obtaining these rights, it intends to engage in the business of accepting and vaporizing liquid natural gas delivered by liquid natural gas tankers, transporting the vaporized liquid natural gas through proprietary gas pipelines and selling the vaporized natural gas to third party customers located in California. As of the date of this report, the limited liability company had not yet engaged in any revenue generating activities. The Company has accounted for its investment at cost. This investment is recorded under Long term assets.

On June 20, 2003, the Company acquired producing oil and gas interests and related undeveloped acreage in Kansas from JAED Production Company “JAED”, an unrelated entity. The Company paid $9 million and issued 200,000 shares of common stock. The shares issued were recorded at a stock price of $4.61, a five day average closing price surrounding the announcement of the transaction. The Company recorded a purchase price adjustment of approximately $291,000 which reflects the net revenues after operating costs and acquisition related costs from the effective date of June 1, 2003 through the closing date of June 20, 2003. The total acquisition cost of $9.6 million was allocated between proved developed producing of $7.6 million and proved undeveloped of $2 million.

On February 19, 2002, Delta completed the acquisition of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Delta issued 1,377,240 shares of restricted common stock for 100% of the shares of Piper. The 1,377,240 shares of restricted common stock were valued at approximately $5.2 million based on the five-day average closing price surrounding the announcement of the merger. In addition, Delta issued 51,000 shares for the cancellation of certain debt of Piper. As a result of the acquisition, the Company acquired Piper’s working and royalty interests in over 700 gross (4.6 net) wells which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. On May 24, 2002 the Company completed the sale of our undivided interests in Australia, to Tipperary Corporation, in exchange for Tipperary’s producing properties in the West Buna Field (Hardin and Jasper counties, Texas) which had a fair market value of approximately $4.1 million, $700,000 in cash, and 250,000 unregistered shares of Tipperary common stock. No gain or loss was recorded on this transaction. In addition, on May 28, 2002, the Company sold a commercial office building obtained in the merger with Piper located in Fort Worth, Texas to a non-affiliate for its fair value of $417,000. No gain or loss was recorded on this transaction. The total acquisition cost, net of purchase price adjustments, of approximately $4.8 million was allocated between proved developed producing of $3.9 million, proved developed non-producing of $336,000, and proved undeveloped of $585,000. Net daily production from the West Buna Field approximates 900,000 cubic feet equivalent.

On May 31, 2002, the Company acquired all of the domestic oil and gas properties of Castle Energy Corporation. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. The Company issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price. The shares issued were recorded at a stock price of $3.97, the closing stock price at May 31, 2002, discounted by 30% according to a fair market appraisal of Delta’s stock obtained from Snyder & Company, an independent valuation expert.

The Company was entitled to repurchase up to 3,188,667 of our shares from Castle for $4.50 per share for a period of one year after closing (May 31, 2003). The Company did not repurchase its shares on May 31, 2003. This right is reflected in stockholders’ equity at its fair value as a put option on Delta stock until expiration. The Company’s agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date were recorded as an adjustment to the purchase price. As a part of the acquisition, upon closing, Delta granted an option to acquire a 4% working interest in the properties acquired for a cost of $878,000 to BWAB Limited Liability Company (“BWAB”), a less than 10% shareholder of Delta. The difference between the $878,000 paid by BWAB which was less than fair value, and 4% of the cost of the Castle properties was treated as an additional acquisition cost by Delta for its consultation and assistance related to the transaction.

The Company recorded a purchase price adjustment of approximately $5.8 million which reflects the net revenues after operating costs and acquisition related costs from the effective date of October 1, 2001 through the closing date of May 31, 2002. The total acquisition cost of approximately $40.8 million 767,000 was allocated between proved developed producing of $32.6 million and proved undeveloped of $8.2 million. The Company recorded oil and gas revenues of $1.1 million and operating expenses of $485,000 for the month of June 2002 relating to these properties.

In addition to the acquisitions described above, the Company acquired additional oil and gas properties in Colorado, Oklahoma and Texas during fiscal 2002. The consideration for these acquisitions was $667,000 and 137,476 shares of the Company’s restricted common stock with a fair value of $375,000 based on the market price on the date of closing.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations and gain (loss) relating to the sale of the following property interests have been reflected as discontinued operations.

On March 31, 2004, the Company completed the sale of all of our Pennsylvania properties to Castle Energy Corporation, a 25% shareholder of Delta at March 31, 2004, for cash consideration of $8 million, which the Company believes is fair value, with an effective date of January 1, 2004 and resulted in a gain on sale of oil and gas properties of $1.9 million. Revenues from the sale of these oil and properties were approximately $1.2 million for the nine months ended March 31, 2004 and $1.8 million for the year ended June 30, 2003.

On December 5, 2003, the Company completed the sale of certain properties located in Texas to Sovereign for cash consideration of $2.6 million. The effective date of the transaction is January 1, 2004 and it resulted in a loss on the sale of oil and gas properties of $28,000. Revenues attributed to the sale of these oil and gas properties were approximately $537,000 for the nine months ended March 31, 2004 and $1.2 million for the year ended June 30, 2003.

On March 1, 2002, Delta completed the sale of 21 producing wells and acreage located primarily in the Eland and Stadium fields of Stark County, North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited liability company, for cash consideration of $2.8 million pursuant to a purchase and sale agreement dated February 1, 2002 and effective January 1, 2002. The Company recorded an impairment on these properties of $102,000 prior to the sale. As a result of the sale, the Company recorded a loss on the sale of these oil and gas properties of $1,000. Approximately $1.3 million of the proceeds from the sale were used to pay existing debt.

During the years ended June 30, 2003 and 2002, the Company disposed of additional non-strategic oil and gas properties and related equipment to unaffiliated entities in addition to the dispositions described above. The Company has received proceeds from these sales of $850,000 and $1.5 million and such sales resulted in a net gain (loss) on sale of oil and gas properties of $277,000 and $(87,000) for the years ended June 30, 2003 and 2002, respectively.

On June 29, 2004, the Company amended and restated its credit facility. The new $100 million facility with Bank of Oklahoma, U.S. Bank National Association and Hibernia National Bank (the “Banks”). At June 30, 2004, the Company had an available borrowing base of $70 million and was fully funded. The facility has a variable interest rate of LIBOR +1.75% to 2.85% and/or prime +.5% / - -.5% based on the total debt outstanding and no current monthly commitment reduction. The loan matures on June 30, 2007 and is collateralized by substantially all of Delta’s oil and gas properties. The Company’s borrowing base and monthly commitment amount will be redetermined at least semi-annually. See Subsequent event footnote for activity after year end.

If as a result of any such monthly commitment reduction or reduction in the amount of the borrowing base, the total amount of our outstanding debt ever exceeds the amount of the revolving commitment then in effect, then within 30 days after the Company is notified by the Bank of Oklahoma, the Company must make a mandatory prepayment of principal that is sufficient to cause the Company’s total outstanding indebtedness to not exceed the borrowing base. The Company is required to meet quarterly debt covenants and restrictions, which includes a current ratio to be not less than 1.0 to 1.0 and a funded debt ratio to not be greater than 3.0 to 1.0 after adjustments. At June 30, 2004, the Company was in compliance with its quarterly debt covenants and restrictions.

On December 1, 1999, the Company borrowed $8 million at prime plus 1¹/2% from Kaiser Francis Oil Company. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit and New Mexico acquisitions. During the third quarter of fiscal 2004, the loan was paid in full.

Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:

The Company has 3,000,000 shares of preferred stock authorized, par value $.10 per share, issuable from time to time in one or more series. As of June 30, 2004, 2003 and 2002, no preferred stock was issued.

In addition to the common stock transactions described earlier in Note (2), the Company raised additional capital through the sale of shares of its common stock, net of commissions, of $97.9 million and $225,000 during the years ended June 30, 2004 and 2002, respectively. The Company did not raise capital through the issuance of shares of its common stock during the year-ended June 30, 2003. Offering costs of $6.1 million and $25,000 respectively consisted of cash commission and legal service relating to the transactions and were accounted for as an adjustment to stockholders’ equity.

On May 31, 2002 at the annual meeting of the shareholders, the shareholders ratified the Company’s 2002 Incentive Plan (the “Incentive Plan”) under which it reserved up to an additional 2,000,000 shares of common stock. This plan supercedes the Company’s 1993 and 2001 Incentive Plans.

Incentive awards under the Incentive Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date under our various incentive plans have been non-qualified stock options as defined in such plans. Options are generally issued at market price at the date of grant with various vesting and expiration terms based on the discretion of the Incentive Plan Committee.

A summary of the stock option activity under the Company’s various plans and related information for the years ended June 30, 2004, 2003 and 2002 follows:

The Company issued options to its Non-employee Directors. Accordingly, the Company recorded stock option expense in the amount of $329,000, $114,000 and $113,000 for options issued to its Directors for the years ended June 30, 2004, 2003 and 2002, respectively, for options issued below market.

Exercise prices for options outstanding under our various plans as of June 30, 2004 ranged from $.05 to $9.75 per share. The weighted-average remaining contractual life of those unvested options is 6.5 years. All but 400,000 options are fully vested at June 30, 2004. A summary of the outstanding and exercisable options at June 30, 2004, segregated by exercise price ranges, is as follows:

The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following Weighted-average assumptions for the years ended June 30, 2004, 2003 and 2002, respectively, risk-free interest rate of 4.32%, 2.84% and 4.73%, dividend yields of 0%, 0% and 0%, volatility factors of the expected market price of the Company’s common stock of 50.43%, 65.32% and 65.68% and a weighted-average expected life of the options of 5.56, 4.16 and 6.37 years.

The Company has also issued options to non-employees. Accordingly, the Company recorded stock option expense in the amount of zero, $10,000 and $30,000 to non-employees for the years ended June 30, 2004, 2003 and 2003, respectively.

A summary of the stock option and warrant activity and related information for the years ended June 30, 2004, 2003 and 2002 is as follows:

Exercise prices for options outstanding as of June 30, 2004 ranged from $3.25 to $5.00 per share. All options are fully vested at June 30, 2004. The weighted-average remaining contractual life of those options is .25 years. A summary of the outstanding and exercisable options at June 30, 2004, segregated by exercise price ranges, is as follows:

The Company adopted a profit sharing plan on January 1, 2002. All employees are eligible to participate in and contributions to the profit sharing plan are voluntary and must be approved by the Board of Directors. Amounts contributed to the Plan will vest over a six year service period.

Prior to the adoption of a profit sharing plan, the Company sponsored a qualified tax deferred savings plan in the form of a Savings Incentive Match Plan for Employees (“SIMPLE”) IRA plan available to companies with fewer than 100 employees. Under the SIMPLE plan, the Company’s employees made annual salary reduction contributions of up to 3% of an employee’s base salary up to a maximum of $6,000 (adjusted for inflation) on a pre-tax basis. The Company matched contributions on behalf of employees who met certain eligibility requirements.

For the years ended June 30, 2004, 2003 and 2002 the Company contributed $262,000, $147,000 and $68,000, respectively under the plans.

The Company periodically enters into commodity price risk transactions to manage its exposure to oil and gas price volatility. These transactions may take the form of futures contracts, swaps or options. All transactions are accounted for in accordance with requirements of SFAS No. 133 which the Company adopted on January 1, 2001. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts which qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to realized gain (loss) on derivative instruments as the associated production occurs.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk activities.

As of June 30, 2004, the Company had no derivative instruments in place. The realized net losses from hedging activities were $859,000 and $1.9 million for the years ended June 30, 2004 and 2003.

At June 30, 2004, 2003 and 2002, the Company’s significant deferred tax assets and liabilities are summarized as follows:

No income tax benefit has been recorded for the years ended June 30, 2004, 2003 or 2002 since the benefit of the net operating loss carryforward and other net deferred tax assets arising in those periods has been offset by the valuation allowance for such net deferred tax assets. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is not more likely than not that the Company will realize the benefits of these deductible differences at June 30, 2004. The amount of the deferred tax asset considered realizable to offset deferred tax liabilities, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

At June 30, 2004, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $35 million and $33.1 million, respectively. If not utilized, the tax net operating loss carryforwards will expire during the period from 2005 through 2024. If not utilized, approximately $2.8 million of net operating losses will expire over the next five years. Net operating loss carryforwards attributable to Amber prior to 1993 of approximately $362,000, included in the above amounts, are available only to offset future taxable income of Amber.

In addition, Delta Petroleum and its subsidiaries experienced a change in ownership in May 2002 with the acquisition of Castle’s oil and gas properties and as a result, its annual net operating loss carry-forward usage is limited. The annual limitation due to the ownership change is estimated to be approximately $3 million.

Until March 12, 2003, the Company’s Board of Directors had granted each of our officers the right to participate in the drilling on the same terms as the Company in up to a five percent (5%) working interest in any well drilled, re-entered, completed or recompleted by us on our acreage (provided that any well to be re-entered or recompleted was then producing economic quantities of hydrocarbons). On March 12, 2003, the Board of Directors rescinded this right. The officers did not participate in any Company wells during fiscal 2003.

Effective June 1, 2002, Mr. Parker exchanged properties with a fair market value of approximately $150,000 in exchange for a reduction in joint interest billing owed to the Company. The fair market value was initially determined by the Company’s engineer and verified by an independent engineer.

During fiscal 2001 and 2000, Mr. Larson and Mr. Parker guaranteed certain borrowings which have subsequently been paid in full. As consideration for the guarantee of the Company’s indebtedness, each officer was assigned a 1% overriding royalty interest (“ORRI”) in the properties acquired with the proceeds of the borrowings. Each officer earned approximately $66,000, $108,000 and $71,000 for their respective 1% ORRI during fiscal 2004, 2003 and 2002, respectively.

The Company’s officers have employment agreements, which among other things include termination and change of control clauses. These employment agreements terminate in November 2004.

At June 30, 2004, the Company had $18,000 of receivables from related parties. These amounts include drilling costs, and lease operating expense on wells owned by the related parties and operated by the Company. The amounts were paid in full subsequent to year end.

The following table sets forth the computation of basic and diluted earnings per share:

The Company rents an office in Denver under an operating lease which expires in fiscal 2009. Rent expense, for the years ended June 30, 2004, 2003 and 2002 was approximately $272,000, $210,000 and $109,000, respectively. Future minimum payments under non-cancelable operating leases are as follows:

Fiscal 2003 4th Quarter includes bonuses of $676,000 and dry hole costs of $405,000.

(13) Disclosures About Capitalized Costs, Cost Incurred and Major Customers, Continued

A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, is as follows:

Statement of Financial Accounting Standards 131 “Disclosures about segments of an enterprises and Related Information” (SFAS 131) establishes standards for reporting information about operating segments in annual and interim financial statements. SFAS 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. The Company’s business segment includes its onshore and offshore properties described above and its drilling and trucking companies. The drilling and trucking companies had minimal activity. As such, segment information relating to the drilling and trucking companies have not been presented.

The Company’s sales of oil and gas to individual customers which exceeded 10% of the Company’s total oil and gas sales for the years ended June 30, 2004, 2003 and 2002 were:

Proved Oil and Gas Reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For the purposes of this disclosure, the Company has included reserves it is committed to and anticipates drilling.

(i) Reservoirs are considered proved if economic producability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

(14) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

A summary of changes in estimated quantities of proved reserves for the years ended June 30, 2004, 2003 and 2002 are as follows:

(14) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

Future net cash flows presented below are computed using year-end prices and costs and are net of all overriding royalty revenue interests.

(14) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

The principal sources of changes in the standardized measure of discounted net cash flows during the years ended June 30, 2004, 2003 and 2002 are as follows:

On August 19, 2004, the Company completed the sale of certain interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $19.3 million. The Company paid $8.8 million toward its credit facility relating to the sale of these properties. There was no gain or loss on this transaction.

Pursuant to the requirements of the Section 13 or 15 (d) or the Securities Exchange of Act of 1934, we have caused this Form 10-K to be signed on our behalf by the undersigned, thereunto duly authorized, in the City of Denver and State of Colorado on the 10th day of September 2004.


DELTA PETROLEUM CORPORATION

By:		/s/ Roger A. Parker
		Roger A. Parker, President and
		Chief Executive Officer

By:		/s/ Kevin K. Nanke
		Kevin K. Nanke, Treasurer and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons on our behalf and in the capacities and on the dates indicated.


		PAGE
PART I

DESCRIPTION OF BUSINESS		4
DESCRIPTION OF PROPERTY		21
LEGAL PROCEEDINGS		27
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		27
DIRECTORS AND EXECUTIVE OFFICERS		28

PART II

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		31
SELECTED FINANCIAL DATA		32
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		32
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		42
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		43
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS		43
CONTROLS AND PROCEDURES		43

PART III

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K		46


Areas of Operations	Proved Reserves (Bcfe) (1)	% Natural Gas		% Proved Developed		2004 Production (MMcfe/d) (2)
Gulf Coast Region	93.6	46.8	%	33.9	%	5.6
Rocky Mountain Region	12.2	64.0	%	57.9	%	4.5
Offshore California	11.0	—	%	62.0	%	3.0
Other	50.9	71.8	%	63.0	%	6.7

Total	167.7	52.5	%	46.32	%	19.8


	Year Ended June 30, 2004					Year Ended June 30, 2003 (1)					Year Ended June 30, 2002 (1)
	Onshore			Offshore		Onshore			Offshore		Onshore		Offshore
Production volume - continuing operations:
Oil (MBbls)		552			180		217			227		86		262
Natural Gas (Mmcf)		2,842			—		2,492			—		870		—
Net average daily production-continuing operations:
Oil (Bbl)		1,512			493		595			621		236		718
Natural Gas (Mcf)		7,786			—		6,827			—		2,384		—
Average sales price:
Oil (per barrel)	$	33.09		$	22.11	$	28.82		$	20.21	$	22.22	$	14.36
Natural Gas (per Mcf)	$	5.27		$	—	$	4.71		$	—	$	2.75	$	—
Hedge effect (per Mcf equivalent)	$	(.14	)	$	—	$	(.49	)	$	—	$	.03	$	—
Production costs
(per Mcf equivalent)	$	1.06		$	3.02	$	1.35		$	2.40	$	.90	$	1.94


	Oil (1)		Gas		Developed Acres
Location	Gross (2)	Net (3)	Gross (2)	Net (3)	Gross (2)	Net (3)
Alabama	0	0	74	55.1	3,526	3,526
California:
Offshore	38	2.3	0	0	1,200	134
Onshore	10	.67	10	3.84	1,160	586
Colorado	21	17.81	9	7.54	3,550	3,508
Kansas	29	26.44	1	.625	840	808
Louisiana	25	13.8	5	1.45	5,968	3,737
Michigan	1	.0096	0	0	40	0
Mississippi	7	.32	4	1.0	1,440	332
Montana	11	3.64	1	.48	964	241
Nebraska	1	.0625	0	0	40	3
New Mexico	12	1.21	21	5.38	9,280	2,574
North Dakota	18	1.25	0	0	9,910	2,302
Oklahoma	5	5.76	3	.07	2,385	28
Texas (4)	93	49.66	138	42.47	26,562	12,552
Wyoming	1	1	16	5.91	7,200	720

	272	123.93	282	123.87	74,065	31,051


	Undeveloped Acres (1) (2)
Location	Gross	Net
California, offshore(3)	64,905	15,837
Colorado	396,988	300,297
Montana	26,841	22,466
North Dakota	880	528
Texas	1,493	1,119
Washington	239,205	106,629
Wyoming	25,567	17,961

Total	755,879	464,837


	Year Ended June 30, 2004		Year Ended June 30, 2003		Year Ended June 30, 2002
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells (1):
Productive:
Oil	3	1.40	0	0.00	0	0.00
Gas	1	.25	0	0.00	0	0.00
Nonproductive	5	3.25	3	1.55	5	2.70

Total	9	4.90	3	1.55	5	2.70

Development Wells (1):
Productive:
Oil	3	2.81	0	0.00	4	.24
Gas	22	9.46	6	5.15	6	0.49
Nonproductive	3	3.00	0	0.00	0	0.00

Total	28	15.27	6	5.15	10	.73

Total Wells (1):
Productive:
Oil	6	4.21	0	0.00	4	.242
Gas	23	9.71	6	5.15	6	2.70
Nonproductive	8	6.25	3	1.55	5	0.49

Total Wells	37	20.17	9	6.70	15	3.43


Areas of Operations	Drilling Locations	Budget
		(In millions)
Gulf Coast Region	18 - 23	$ 22 - $ 29
Rocky Mountain Region	130 - 162	$ 36 - $ 45
Offshore California	3 - 5	$ 2 - $ 4
Other	0 - 5	$ 0 - $ 2

Total	153 - 200	$ 60 - $ 80


Name	Age	Positions	Period of Service
Roger A. Parker	42	President, Chief Executive Officer and a Director	May 1987 to Present

Aleron H. Larson, Jr.	59	Chairman of the Board, Secretary and a Director	May 1987 to Present

Kevin K. Nanke	39	Treasurer and Chief Financial Officer	December 1999 to Present

John R. Wallace	43	Executive V.P., Exploration and Chief Operating Officer	October 2003 to Present

Jerrie F. Eckelberger	59	Director	September 1996 to Present

James B. Wallace	74	Director	November 2001 to Present

Joseph L. Castle II	71	Director	June 2002 to Present

Russell S. Lewis	48	Director	June 2002 to Present

John P. Keller	64	Director	June 2002 to Present


Quarter Ended	High		Low
September 30, 2002	$	3.94	$	1.25
December 31, 2002		4.10		3.01
March 31, 2003		4.05		3.15
June 30, 2003		5.00		3.25
September 30, 2003		5.73		4.12
December 31, 2003		6.30		4.75
March 31, 2004		11.19		6.04
June 30, 2004		15.93		10.00


	Fiscal Years Ended June 30,
	2004		2003		2002			2001		2000
	(In thousands, except per share amounts)
Total Revenues	$	36,376	$	20,718	$	8,052		$	12,712	$	3,576
Income/(Loss) from Continuing Operations	$	3,867	$	1,495	$	(4,944	)	$	1,619	$	(2,079	)
Net Income (Loss)	$	5,056	$	1,257	$	(6,253	)	$	345	$	(3,367	)
Income/(Loss) Per Common Share
Basic	$	.19	$	.05	$	(.49	)	$	.03	$	(.46	)
Diluted	$	.17	$	.05	$	(.49	)	$	.03	$	(.46	)
Total Assets	$	272,704	$	86,847	$	74,077		$	29,832	$	21,057
Total Liabilities	$	86,462	$	38,944	$	29,161		$	11,551	$	10,094
Minority Interest	$	245	$	—	$	—		$	—	$	—
Stockholders’ Equity	$	185,997	$	47,903	$	44,916		$	18,281	$	10,963
Total Long Term Liabilities	$	72,386	$	33,082	$	24,939		$	9,434	$	8,245


	Payments Due by Period
Contractual Obligations	Less than 1 year		2-3 Years		4-5 Years		After 5 Years		Total
	(In thousands)
Bank credit facility	$	—	$	69,375	$	—	$	—	$	69,375
Drilling obligation		2,250		4,500		4,500		—		11,250
Abandonment retirement obligation		105		263		331		4,685		5,384
Operating leases and other debt obligations		463		940		464		—		1,867

Total contractual cash obligations	$	2,818	$	75,078	$	5,295	$	4,685	$	87,876


	2004					2003 (1)
	Onshore			Offshore		Onshore			Offshore
Production:
Oil (MBbl)		552			180		217			227
Gas (Mmcf)		2,842			—		2,492			—
Production – Discontinued Operations:
Oil (MBbl)		16			—		35			—
Gas (Mmcf)		268			—		446			—
Average Price – Continuing Operations:
Oil (per barrel)	$	33.09		$	22.11	$	28.82		$	20.21
Gas (per Mcf)	$	5.27		$	—	$	4.71		$	—
Hedge effect
(per Mcf equivalent)	$	(.14	)	$	—	$	(.49	)	$	—
Production Costs:
(per Mcf equivalent)	$	1.06		$	3.02	$	1.35		$	2.40
Depletion Expense:
(per Mcf equivalent)	$	1.46		$	.65	$	1.02		$	.79


	2003 (1)					2002 (1)
	Onshore			Offshore		Onshore		Offshore
Production:
Oil (MBbl)		217			227		86		262
Gas (Mmcf)		2,492			—		870		—
Production – Discontinued Operations:
Oil (MBbl)		35			—		3		—
Gas (Mmcf)		446			—		1		—
Average Price – Continuing Operations:
Oil (per barrel)	$	28.82		$	20.21	$	22.22	$	14.36
Gas (per Mcf)	$	4.71		$	—	$	2.75	$	—
Hedge effect
(per Mcf equivalent)	$	(.49	)	$	—	$	.03	$	—
Production Costs:
(per Mcf equivalent)	$	1.35		$	2.40	$	.90	$	1.94
Depletion Expense:
(per Mcf equivalent)	$	1.02		$	.79	$	1.58	$	.69


		Page No.
Report of Independent Registered Accounting Firm		F-1

Consolidated Balance Sheets at June 30, 2004 and 2003		F-2

Consolidated Statements of Operations for the years ended June 30, 2004, 2003 and 2002		F-3

Consolidated Statement of Stockholders’ Equity and Comprehensive Income (Loss) for the years ended June 30, 2004, 2003 and 2002		F-4

Consolidated Statements of Cash Flows for the years ended June 30, 2004, 2003 and 2002		F-5

Notes to Consolidated Financial Statements		F-6



2.		Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession. Not applicable.

3.		Articles of Incorporation and By-laws.

3.1		Articles of Incorporation and Articles of Amendment to Articles of Incorporation. Filed herewith electronically.

3.2		By-laws. Incorporated by reference from Exhibit 3.3 to the Company’s Form 10 Registration Statement under the Securities Exchange Act of 1934, filed September 9, 1987.

4.		Instruments Defining the Rights of Security Holders. Not applicable.

9.		Voting Trust Agreement. Not applicable.

10.		Material Contracts.

10.1		Burdette A. Ogle “Assignment, Conveyance and Bill of Sale of Federal Oil and Gas Leases Reserving a Production Payment,” “Lease Interests Purchase Option Agreement” and “Purchase and Sale Agreement.” Incorporated by reference from Exhibit 28.1 to the Company’s Form 8-K dated January 3, 1995.

10.2		Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1996. *

10.3		Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated June 1, 1999. *

10.4		Agreement between Burdette A. Ogle and Delta Petroleum Corporation effective December 17, 1998. Incorporated by reference from Exhibit 99.2 to the Company’s Form 10-QSB for the quarterly period ended December 31, 1998.

10.5		Agreement between Whiting Petroleum Corporation and Delta Petroleum Corporation (including amendment) dated June 8, 1999. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated June 9, 1999.

10.6		Purchase and Sale Agreement dated October 13, 1999 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company’s Form 8-K dated November 1, 1999.

10.7		Agreement between Delta Petroleum Corporation, Roger A. Parker and Aleron H. Larson, Jr. dated November 1, 1999. Incorporated by reference from Exhibit 99.3 to the Company’s Form 8-K dated November 1, 1999.*

10.8		Conveyance and Assignment from Whiting Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated December 1, 1999.

10.9		Agreement dated December 30, 1999 between Burdette A. Ogle and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.4 to the Company’s Form 8-K dated January 4, 2000.

10.10		Purchase and Sale Agreement dated June 1, 2000 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated July 10, 2000.



10.11		Delta Petroleum Corporation 2001 Incentive Plan. Incorporated by reference to the Company’s Notice of Annual Meeting and Proxy Statement dated July 26, 2001 for fiscal year 2000 ended June 30, 2000.*

10.12		Employment Agreements with Aleron H. Larson, Jr., Roger A. Parker and Kevin K. Nanke, from Exhibit 10.4 a, b, and c to the Company’s Form 8-K dated October 25, 2001. *

10.13		Delta Petroleum Corporation 2002 Incentive Plan incorporated by reference from Exhibit A to the Company’s definitive proxy statement filed May 1, 2002. *

10.14		Agreement between Delta Petroleum Corporation and Amber Resources Company dated July 1, 2001, incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated October 25, 2001.

10.15		Letter agreement dated December 3, 2001 between Delta Petroleum Corporation and Ogle Properties LLC, incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated October 25, 2001.

10.16		Purchase and Sale Agreement between Castle Energy Company and Delta Petroleum Corporation dated December 31, 2001 incorporated by reference from Exhibit 2.1 to the Company’s Form 8-K dated January 15, 2002.

10.17		Purchase and Sale Agreement between Delta Petroleum Corporation and Tipperary Oil & Gas Corporation dated May 8, 2002 incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated April 30, 2002.

10.18		Credit Agreement dated May 31, 2002 by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated May 24, 2002.

10.19		First Amendment to Credit Agreement dated June 20, 2003 by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated June 20, 2003.

10.20		Agreement with Arguello, Inc. Incorporated by reference from Exhibit10.22 to the Company’s Form 10-K for the fiscal year ended June 30, 2003.

10.21		Purchase and Sale Agreement dated as of June 5, 2003 between JAED Production Company, Inc. and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 20, 2003.

10.22		Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated September 19, 2003.

10.23		First Amendment to Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated September 19, 2003.

10.24		Amended and Restated Credit Agreement dated December 30, 2003, by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference from Exhibit 10.1 to the Company’s Form 10-Q dated December 31, 2003.

10.25		Second Amendment to Purchase and Sale Agreement with Edward Mike Davis and Edward Mike Davis, L.L.C. Incorporated by reference from Exhibit 10.4 to the Company’s Form 8-K dated April 23, 2004.



10.26		Purchase and Sale Agreement dated June 10, 2004 with various sellers related to Alpine Resources, Inc. Incorporated by reference from Exhibit 10.1 to the Company’s Form 8-K dated June 29, 2004.

10.27		Second Amendment of Amended and Restated Credit Agreement dated June 29, 2004 with Bank of Oklahoma, N.A., US Bank National Association and Hibernia National Bank. Incorporated by reference from Exhibit 10.2 to the Company’s Form 8-K dated June 29, 2004.

10.28		Amendment No. 1 to Purchase and Sale Agreement dated July 7, 2004 with Edward Mike Davis and entities controlled by him. Incorporated by reference from Exhibit 10.3 to the Company’s Form 8-K dated June 29, 2004.

11.		Statement Regarding Computation of Per Share Earnings. Not applicable.

12.		Statement Regarding Computation of Ratios. Not applicable.

21.		Subsidiaries of the Registrant. Filed herewith electronically.

23.1		Consent of KPMG LLP. Filed herewith electronically.

31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.

32.1		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.

32.2		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.


	June 30, 2004			June 30, 2003
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	2,078		$	2,271
Marketable securities available for sale		912			662
Trade accounts receivable, net of allowance for doubtful accounts		9,092			4,410
Prepaid assets		1,136			764
Inventory of oil field equipment		1,350			—
Other current assets		385			560

Total current assets		14,953			8,667

Property and Equipment:
Oil and gas properties, successful efforts method of accounting		272,892			90,151
Drilling and trucking equipment		3,965			—
Other		1,147			336

Total property and equipment		278,004			90,487
Less accumulated depreciation and depletion		(21,665	)		(12,669	)

Net property and equipment		256,339			77,818

Long term assets:
Investment in LNG project		1,022			—
Deferred financing costs		131			117
Partnership net assets		259			245

Total long term assets		1,412			362
	$	272,704		$	86,847

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current portion of long-term debt	$	109		$	10,039
Accounts payable		12,326			3,604
Other accrued liabilities		1,855			1,087
Derivative instruments		—			468
Current foreign tax payable		—			703

Total current liabilities		14,290			15,901

Long-term Liabilities:
Bank debt, net		69,375			22,175
Asset retirement obligation		2,542			868
Other debt, net		255			—

Total long-term liabilities		72,172			23,043

Minority Interest		245			—

Stockholders’ Equity:
Preferred stock, $.10 par value: authorized 3,000,000 shares, none issued		—			—
Common stock, $.01 par value; authorized 300,000,000 shares, issued 38,447,000 shares at June 30, 2004 and 23,286,000 shares at June 30, 2003		384			233
Additional paid-in capital		207,811			75,642
Accumulated other comprehensive (loss) income		342			(376	)
Accumulated deficit		(22,540	)		(27,596	)

Total stockholders’ equity		185,997			47,903

Commitments and contingencies	$	272,704		$	86,847


	Years Ended June 30,
	2004			2003			2002
	(In thousands, except per share amounts)
Revenue:
Oil and gas sales	$	37,235		$	22,576		$	8,013
Realized gain (loss) on derivative instruments, net		(859	)		(1,858	)		39

Total revenue		36,376			20,718			8,052

Operating expenses:
Production costs		9,776			8,410			4,257
Drilling and trucking operations		232			—			—
Exploration expense		2,406			140			155
Depreciation and depletion		9,914			4,999			3,326
Dry hole costs		2,132			537			396
Abandoned and impaired oil and gas properties		—			—			1,480
Professional fees		1,174			842			1,322
General and administrative (includes stock compensation of $329,000, $123,000 and $143,000 for the years ended June 30, 2004, 2003 and 2002 respectively.)		6,875			4,295			2,060

Total operating expenses		32,509			19,223			12,996

Income (loss) from continuing operations		3,867			1,495			(4,944	)

Other income and (expense):
Other income		122			31			113
Minority interest		70			—			—
Interest and financing costs		(1,762	)		(1,767	)		(1,325	)

Total other expense		(1,570	)		(1,736	)		(1,212	)

Income (loss) before discontinued operations and cumulative effect of change in accounting principle	$	2,297		$	(241	)	$	(6,156	)

Discontinued operations:
Income (loss) from operations of properties sold, net		872			1,241			(9	)
Gain (loss) on sale of properties		1,887			277			(88	)

Income (loss) before cumulative effect of change in accounting principle		5,056			1,277			(6,253	)
Cumulative effect of change in accounting principle		—			(20	)		—

Net income (loss)	$	5,056		$	1,257		$	(6,253	)

Basic income (loss) per common share:
Income (loss) before discontinued operations and cumulative effect of change in accounting principle	$	.09		$	(.01	)	$	(.49	)
Discontinued operations		.10			.06			*

Income (loss) before cumulative effect of change in accounting principle		.19			.05			(.49	)
Cumulative effect of change in accounting principle		—			*			—

Net income (loss)	$	.19		$	.05		$	(.49	)

Diluted income (loss) per common share:
Income (loss) before discontinued operations and cumulative effect of change in accounting principle	$	.08		$	(.01	)	$	(.49	)
Discontinued operations		.09			.06			*

Income (loss) before cumulative effect of change in accounting principle		.17			.05			(.49	)
Cumulative effect of change in accounting principle		—			*			—

Net income (loss)	$	.17		$	.05		$	(.49	)


	Common stock				Additional paid-in capital			Put option on Delta stock			Accumulated other comprehensive income/(loss)			Comprehensive income (loss)		Accumulated deficit			Total
	Shares		Amount		Additional paid-in capital			Put option on Delta stock			Accumulated other comprehensive income/(loss)			Comprehensive income (loss)		Accumulated deficit			Total
	(In thousands, except per share amounts)
Balance July 1, 2001	11,160		$	112	$	40,700		$	—		$	69				$	(22,600	)	$	18,281

Comprehensive loss:
Net loss	—			—		—			—			—		(6,253	)		(6,253	)		(6,253	)
Other comprehensive loss, net of tax
Unrealized loss on equity securities	—			—		—			—			(154	)	(154	)					(154	)

Comprehensive loss	—			—		—			—			—		(6,407	)

Stock options granted as compensation	—			—		143			—			—					—			143
Shares issued for cash, net of commissions	72			1		224			—			—					—			225
Shares issued for cash upon exercise of options	266			2		405			—			—					—			407
Shares issued for services	14			—		48			—			—					—			48
Shares issued for oil and gas properties	9,703			97		26,862			—			—					—			26,959
Put option on Delta Stock	—			—		2,886			(2,886	)		—					—			—
Shares issued for all outstanding shares of Piper Petroleum Company	1,377			14		5,220			—			—					—			5,234
Shares issued for debt	51			—		157			—			—					—			157
Shares reacquired and retired	(25	)		—		(131	)		—			—					—			(131	)

Balance, June 30, 2002	22,618			226		76,514			(2,886	)		(85	)				(28,853	)		44,916

Comprehensive income:
Net income	—			—		—			—			—		1,257			1,257			1,257
Other comprehensive income, net of tax
Change in fair value of derivative hedging instruments	—			—		—			—			(468	)	(468	)		—			(468	)

Unrealized gain on equity securities, net	—			—		—			—			177		177			—			177

Comprehensive income	—			—		—			—			—		966

Stock options granted as compensation						124			—			—					—			124
Put option on Delta Stock	—			—		(2,886	)		2,886											—
Shares issued for oil and gas properties	200			2		920			—			—					—			922
Shares issued for cash upon exercise of options	468			5		970			—			—					—			975

Balance, June 30, 2003	23,286			233		75,642			—			(376	)				(27,596	)		47,903

Comprehensive income:
Net income	—			—		—			—			—		5,056			5,056			5,056
Other comprehensive gain, net of tax
Change in fair value of derivative hedging instruments	—			—		—			—			468		468			—			468
Unrealized gain on equity securities, net	—			—		—			—			250		250			—			250

Comprehensive income	—			—		—			—			—		5,774

Stock options granted as compensation						329			—			—					—			329
Shares issued for cash, net	10,000			100		97,802			—			—					—			97,902
Shares issued for oil and gas properties	3,728			37		30,489			—			—					—			30,526
Shares issued for cash upon exercise of options	1,433			14		3,549			—			—					—			3,563

Balance, June 30, 2004	38,447		$	384	$	207,811		$	—		$	342				$	(22,540	)	$	185,997


	Cost		Unrealized Gain (Loss)			Estimated Market Value
			(In thousands)
June 30, 2004
Bion Environmental Technologies, Inc.	$	152	$	(138	)	$	14
Tipperary Oil & Gas Company		418		480			898

	$	570	$	342		$	912

June 30, 2003
Bion Environmental Technologies, Inc.	$	152	$	(140	)	$	12
Tipperary Oil & Gas Company		418		232			650

	$	570	$	92		$	662

June 30, 2002
Bion Environmental Technologies, Inc.	$	152	$	(92	)	$	60
Tipperary Oil & Gas Company		418		7			425

	$	570	$	(85	)	$	485


	Year Ended June 30,
	2004			2003			2002
	(In thousands, except per share amounts)
Net income (loss)	$	5,056		$	1,257		$	(6,253	)
FAS 123 compensation effect		(4,316	)		(209	)		(790	)

Net Income (loss) after FAS 123 compensation effect	$	740		$	1,048		$	(7,043	)

Income (loss) per common share:
Basic	$	.03		$	.05		$	(.55	)

Diluted	$	.02		$	.04		$	(.55	)


YEAR ENDING June 30,
2005	$	109
2006		112
2007		69,486
2008		24
2009		8

	$	69,739


Exercise Price Range	Options Outstanding	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Exercisable Options	Weighted Average Exercise Price
$0.05 - $1.12	180,000	$	0.05	4.25	180,000	$	0.05
$1.13 - $3.25	1,119,272		2.05	5.95	1,119,272		2.05
$3.26 - $9.75	3,401,500		4.99	7.43	3,001,500		5.12

	4,700,772	$	4.10	6.95	4,300,772	$	4.11


Fiscal 2004	1^st Quarter(1)		2^nd Quarter(1)		3^rd Quarter(1)		4^th Quarter
	(In thousands, except per share amounts)
Total revenue	$	7,444	$	8,006	$	10,342	$	11,641
Income from continuing operations		1,853		1,208		813		621
Net income		1,364		652		2,454		586
Net income per common share: (2)
Basic	$	.06	$	.03	$	.09	$	.02
Diluted	$	.05	$	.03	$	.08	$	.02

Fiscal 2003	1^st Quarter(1)		2^nd Quarter(1)		3^rd Quarter(1)		4^th Quarter(1)
	(In thousands, except per share amounts)
Total revenue	$	5,648	$	5,704	$	6,975	$	5,653
Income (loss) from continuing operations		634		850		1,715		(186	)
Net income (loss)		117		428		1,307		(595	)
Net income (loss) per common share: (2)
Basic	$	.01	$	.02	$	.06	$	(.03	)
Diluted	$	**	$	.02	$	.05	$	*


	June 30,
	2004			2003
	(In thousands)
Unproved undeveloped offshore California properties	$	10,844		$	10,164
Unproved undeveloped onshore domestic properties		38,903			1,680
Proved undeveloped offshore California properties		—			843
Proved undeveloped onshore domestic properties		86,720			9,995
Proved developed offshore California properties		9,103			7,190
Proved developed onshore domestic properties		127,322			60,279

		272,892			90,151
Accumulated depreciation and depletion		(21,317	)		(12,509	)

	$	251,575		$	77,642


	Onshore						Offshore
	GAS (Mmcf)			OIL (MBbl)			GAS (Mmcf)		OIL (MBbl)
	(In thousands)
Balance at July 1, 2001	$	4,682		$	344		$	—	$	1,213

Revisions of quantity estimate		(269	)		71			—		(49	)
Extensions and discoveries		42			2			—		—
Purchase of properties		43,680			3,845			—		—
Sales of properties		(3,311	)		(256	)		—		—
Production		(871	)		(87	)		—		(262	)

Balance at June 30, 2002		43,953			3,919			—		902

Revisions of quantity estimate		13,719			(927	)		—		244
Extensions and discoveries		687			—			—		1,132
Purchase of properties		236			1,024			—		—
Sale of properties		(457	)		(66	)		—		—
Production		(2,938	)		(252	)		—		(227	)

Balance at June 30, 2003		55,200			3,698			—		2,051

Revisions of quantity estimate		(3,136	)		469			—		(44	)
Extensions and discoveries		6,560			69			—		—
Purchase of properties		39,782			8,306			—		—
Sale of properties		(6,817	)		(596	)		—		—
Production		(3,110	)		(568	)		—		(180	)

Balance at June 30, 2004		88,479			11,378			—		1,827

Proved developed reserves:

June 30, 2001		4,474			342			—		906
June 30, 2002		25,100			1,651			—		849
June 30, 2003		28,611			2,608			—		919
June 30, 2004		55,786			6,240			—		695


	Onshore		Offshore		Combined
	(In thousands)
June 30, 2004
Future net cash flows	$	953,532	$	51,625	$	1,005,157
Future costs:
Production		225,046		23,558		248,604
Development		55,845		11,054		66,899
Income taxes		165,492		—		165,492

Future net cash flows		507,149		17,013		524,162
10% discount factor		230,540		5,585		236,125

Standardized measure of discounted future net cash flows	$	276,609	$	11,428	$	288,037

Standardized measure of discounted future net cash flows before tax	$	367,679	$	11,428	$	379,107

Estimated future development cost anticipated for fiscal 2005 and 2006 on existing properties	$	53,129	$	4,378	$	57,507

June 30, 2003
Future cash flows	$	377,458	$	46,898	$	424,356
Future costs:
Production		99,243		24,787		124,030
Development		20,104		13,137		33,241
Income taxes		62,390		—		62,390

Future net cash flows		195,721		8,974		204,695
10% discount factor		93,734		3,750		97,484

Standardized measure of discounted future net cash flows	$	101,987	$	5,224	$	107,211

Standardized measure of discounted future net cash flows before tax	$	134,667	$	5,224	$	139,891

June 30, 2002
Future cash flows	$	247,611	$	16,600	$	264,211
Future costs:
Production		84,109		10,067		94,176
Development		15,056		1,089		16,145
Income taxes		28,078		—		28,078

Future net cash flows		120,368		5,444		125,812
10% discount factor		62,217		1,211		63,428

Standardized measure of discounted future net cash flows	$	58,151	$	4,233	$	62,384

Standardized measure of discounted future net cash flows before tax	$	72,073	$	4,233	$	76,306


Signature and Title		Date
/s/ Aleron H. Larson, Jr.		September 10, 2004
Aleron H. Larson, Jr., Director

/s/ Roger A. Parker		September 10, 2004
Roger A. Parker, Director

/s/ James B. Wallace		September 10, 2004
James B. Wallace, Director

/s/ Jerrie F. Eckelberger		September 10, 2004
Jerrie F. Eckelberger, Director

/s/ John P. Keller		September 10, 2004
John P. Keller, Director

/s/ Joseph L. Castle II		September 10, 2004
Joseph L. Castle II, Director

/s/ Russell S. Lewis		September 10, 2004
Russell S. Lewis, Director